In situ thermal processing of a hydrocarbon containing formation and upgrading of produced fluids prior to further treatment

ABSTRACT

An in situ treatment process may include providing heat from one or more heaters to at least a portion of the formation. The heat may be allowed to transfer from the one or more heaters to a part of the formation. A fluid may be produced from at least part of the formation. Heat and/or other products in or from fluids produced from the formation may be used for hydrotreating.

BACKGROUND OF THE INVENTION

[0001] 1. Field of the Invention

[0002] The present invention relates generally to methods and systemsfor production of hydrocarbons, hydrogen, and/or other products fromvarious hydrocarbon containing formations. Certain embodiments relate toin situ conversion of hydrocarbons to produce hydrocarbons, hydrogen,and/or novel product streams from underground hydrocarbon containingformations.

[0003] 2. Description of Related Art

[0004] Hydrocarbons obtained from subterranean (e.g., sedimentary)formations are often used as energy resources, as feedstocks, and asconsumer products. Concerns over depletion of available hydrocarbonresources and over declining overall quality of produced hydrocarbonshave led to development of processes for more efficient recovery,processing and/or use of available hydrocarbon resources. In situprocesses may be used to remove hydrocarbon materials from subterraneanformations. Chemical and/or physical properties of hydrocarbon materialwithin a subterranean formation may need to be changed to allowhydrocarbon material to be more easily removed from the subterraneanformation. The chemical and physical changes may include in situreactions that produce removable fluids, composition changes, solubilitychanges, density changes, phase changes, and/or viscosity changes of thehydrocarbon material within the formation. A fluid may be, but is notlimited to, a gas, a liquid, an emulsion, a slurry, and/or a stream ofsolid particles that has flow characteristics similar to liquid flow.

[0005] Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom, 2,732,195 toLjungstrom, 2,780,450 to Ljungstrom, 2,789,805 to Ljungstrom, 2,923,535to Ljungstrom, and 4,886,118 to Van Meurs et al., each of which isincorporated by reference as if fully set forth herein.

[0006] Application of heat to oil shale formations is described in U.S.Pat. Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heatmay be applied to the oil shale formation to pyrolyze kerogen within theoil shale formation. The heat may also fracture the formation toincrease permeability of the formation. The increased permeability mayallow formation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

[0007] A heat source may be used to heat a subterranean formation.Electric heaters may be used to heat the subterranean formation byradiation and/or conduction. An electric heater may resistively heat anelement. U.S. Pat. No. 2,548,360 to Germain, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement placed within a viscous oil within a wellbore. The heaterelement heats and thins the oil to allow the oil to be pumped from thewellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which isincorporated by reference as if fully set forth herein, describeselectrically heating tubing of a petroleum well by passing a relativelylow voltage current through the tubing to prevent formation of solids.U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is cemented into a well borehole without a casingsurrounding the heating element.

[0008] U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporatedby reference as if fully set forth herein, describes an electric heatingelement that is positioned within a casing. The heating elementgenerates radiant energy that heats the casing. A granular solid fillmaterial may be placed between the casing and the formation. The casingmay conductively heat the fill material, which in turn conductivelyheats the formation.

[0009] U.S. Pat. No. 4,570,715 to Van Meurs et al., which isincorporated by reference as if fully set forth herein, describes anelectric heating element. The heating element has an electricallyconductive core, a surrounding layer of insulating material, and asurrounding metallic sheath. The conductive core may have a relativelylow resistance at high temperatures. The insulating material may haveelectrical resistance, compressive strength, and heat conductivityproperties that are relatively high at high temperatures. The insulatinglayer may inhibit arcing from the core to the metallic sheath. Themetallic sheath may have tensile strength and creep resistanceproperties that are relatively high at high temperatures.

[0010] U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

[0011] Combustion of a fuel may be used to heat a formation. Combustinga fuel to heat a formation may be more economical than using electricityto heat a formation. Several different types of heaters may use fuelcombustion as a heat source that heats a formation. The combustion maytake place in the formation, in a well, and/or near the surface.Combustion in the formation may be a fireflood. An oxidizer may bepumped into the formation. The oxidizer may be ignited to advance a firefront towards a production well. Oxidizer pumped into the formation mayflow through the formation along fracture lines in the formation.Ignition of the oxidizer may not result in the fire front flowinguniformly through the formation.

[0012] A flameless combustor may be used to combust a fuel within awell. U.S. Pat. Nos. 5,255,742 to Mikus, 5,404,952 to Vinegar et al.,5,862,858 to Wellington et al., and 5,899,269 to Wellington et al.,which are incorporated by reference as if fully set forth herein,describe flameless combustors. Flameless combustion may be accomplishedby preheating a fuel and combustion air to a temperature above anauto-ignition temperature of the mixture. The fuel and combustion airmay be mixed in a heating zone to combust. In the heating zone of theflameless combustor, a catalytic surface may be provided to lower theauto-ignition temperature of the fuel and air mixture.

[0013] Heat may be supplied to a formation from a surface heater. Thesurface heater may produce combustion gases that are circulated throughwellbores to heat the formation. Alternately, a surface burner may beused to heat a heat transfer fluid that is passed through a wellbore toheat the formation. Examples of fired heaters, or surface burners thatmay be used to heat a subterranean formation, are illustrated in U.S.Pat. Nos. 6,056,057 to Vinegar et al. and 6,079,499 to Mikus et al.,which are both incorporated by reference as if fully set forth herein.

[0014] Coal is often mined and used as a fuel within an electricitygenerating power plant. Most coal that is used as a fuel to generateelectricity is mined. A significant number of coal formations are,however, not suitable for economical mining. For example, mining coalfrom steeply dipping coal seams, from relatively thin coal seams (e.g.,less than about 1 meter thick), and/or from deep coal seams may not beeconomically feasible. Deep coal seams include coal seams that are at,or extend to, depths of greater than about 3000 feet (about 914 m) belowsurface level. The energy conversion efficiency of burning coal togenerate electricity is relatively low, as compared to fuels such asnatural gas. Also, burning coal to generate electricity often generatessignificant amounts of carbon dioxide, oxides of sulfur, and oxides ofnitrogen that are released into the atmosphere.

[0015] Synthesis gas may be produced in reactors or in situ within asubterranean formation. Synthesis gas may be produced within a reactorby partially oxidizing methane with oxygen. In situ production ofsynthesis gas may be economically desirable to avoid the expense ofbuilding, operating, and maintaining a surface synthesis gas productionfacility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated byreference as if fully set forth herein, describes a system for in situgasification of coal. A subterranean coal seam is burned from a firstwell towards a production well. Methane, hydrocarbons, H₂, CO, and otherfluids may be removed from the formation through the production well.The H₂ and CO may be separated from the remaining fluid. The H₂ and COmay be sent to fuel cells to generate electricity.

[0016] U.S. Pat. No. 4,057,293 to Garrett, which is incorporated byreference as if fully set forth herein, discloses a process forproducing synthesis gas. A portion of a rubble pile is burned to heatthe rubble pile to a temperature that generates liquid and gaseoushydrocarbons by pyrolysis. After pyrolysis, the rubble is furtherheated, and steam or steam and air are introduced to the rubble pile togenerate synthesis gas.

[0017] U.S. Pat. No. 5,554,453 to Steinfeld et al., which isincorporated by reference as if fully set forth herein, describes an exsitu coal gasifier that supplies fuel gas to a fuel cell. The fuel cellproduces electricity. A catalytic burner is used to burn exhaust gasfrom the fuel cell with an oxidant gas to generate heat in the gasifier.

[0018] Carbon dioxide may be produced from combustion of fuel and frommany chemical processes. Carbon dioxide may be used for variouspurposes, such as, but not limited to, a feed stream for a dry iceproduction facility, supercritical fluid in a low temperaturesupercritical fluid process, a flooding agent for coal beddemethanation, and a flooding agent for enhanced oil recovery. Althoughsome carbon dioxide is productively used, many tons of carbon dioxideare vented to the atmosphere.

[0019] Retorting processes for oil shale may be generally divided intotwo major types: aboveground (surface) and underground (in situ).Aboveground retorting of oil shale typically involves mining andconstruction of metal vessels capable of withstanding high temperatures.The quality of ail produced from such retorting may typically be poor,thereby requiring costly upgrading. Aboveground retorting may alsoadversely affect environmental and water resources due to mining,transporting, processing, and/or disposing of the retorted material.Many U.S. patents have been issued relating to aboveground retorting ofoil shale. Currently available aboveground retorting processes include,for example, direct, indirect, and/or combination heating methods.

[0020] In situ retorting typically involves retorting oil shale withoutremoving the oil shale from the ground by mining. “Modified” in situprocesses typically require some mining to develop underground retortchambers. An example of a “modified” in situ process includes a methoddeveloped by Occidental Petroleum that involves mining approximately 20%of the oil shale in a formation, explosively rubblizing the remainder ofthe oil shale to fill up the mined out area, and combusting the oilshale by gravity stable combustion in which combustion is initiated fromthe top of the retort. Other examples of “modified” in situ processesinclude the “Rubble In Situ Extraction” (“RISE”) method developed by theLawrence Livermore Laboratory (“LLL”) and radio-frequency methodsdeveloped by IIT Research Institute (“IITRI”) and LLL, which involvetunneling and mining drifts to install an array of radio-frequencyantennas in an oil shale formation.

[0021] Obtaining permeability within an oil shale formation (e.g.,between injection and production wells) tends to be difficult becauseoil shale is often substantially impermeable. Many methods haveattempted to link injection and production wells, including: hydraulicfracturing such as methods investigated by Dow Chemical and LaramieEnergy Research Center; electrical fracturing (e.g., by methodsinvestigated by Laramie Energy Research Center); acid leaching oflimestone cavities (e.g., by methods investigated by Dow Chemical);steam injection into permeable nahcolite zones to dissolve the nahcolite(e.g., by methods investigated by Shell Oil and Equity Oil); fracturingwith chemical explosives (e.g., by methods investigated by Talley EnergySystems); fracturing with nuclear explosives (e.g., by methodsinvestigated by Project Bronco); and combinations of these methods. Manyof such methods, however, have relatively high operating costs and lacksufficient injection capacity.

[0022] An example of an in situ retorting process is illustrated in U.S.Pat. No. 3,241,611 to Dougan, assigned to Equity Oil Company, which isincorporated by reference as if fully set forth herein. For example,Dougan discloses a method involving the use of natural gas for conveyingkerogen-decomposing heat to the formation. The heated natural gas may beused as a solvent for thermally decomposed kerogen. The heatednatural-gas exercises a solvent-stripping action with respect to the oilshale by penetrating pores that exist in the shale. The natural gascarrier fluid, accompanied by decomposition product vapors and gases,passes upwardly through extraction wells into product recovery lines,and into and through condensers interposed in such lines, where thedecomposition vapors condense, leaving the natural gas carrier fluid toflow through a heater and into an injection well drilled into thedeposit of oil shale.

[0023] Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar)contained within relatively permeable formations (e.g., in tar sands)are found in North America, South America, Africa, and Asia. Tar can besurface-mined and upgraded to lighter hydrocarbons such as crude oil,naphtha, kerosene, and/or gas oil. Tar sand deposits may, for example,first be mined. Surface milling processes may further separate thebitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

[0024] U.S. Pat. Nos. 5,340,467 to Gregoli et al. and 5,316,467 toGregoli et al., which are incorporated by reference as if fully setforth herein, describe adding water and a chemical additive to tar sandto form a slurry. The slurry may be separated into hydrocarbons andwater.

[0025] U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporatedby reference as if fully set forth herein, describes physicallyseparating tar sand into a bitumen-rich concentrate that may have someremaining sand. The bitumen-rich concentrate may be further separatedfrom sand in a fluidized bed.

[0026] U.S. Pat. Nos. 5,985,138 to Humphreys and 5,968,349 to Duyvesteynet al., which are incorporated by reference as if fully set forthherein, describe mining tar sand and physically separating bitumen fromthe tar sand. Further processing of bitumen in treatment facilities mayupgrade oil produced from bitumen.

[0027] In situ production of hydrocarbons from tar sand may beaccomplished by heating and/or injecting a gas into the formation. U.S.Pat. Nos. 5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, whichare incorporated by reference as if fully set forth herein, describe ahorizontal production well located in an oil-bearing reservoir. Avertical conduit may be used to inject an oxidant gas into the reservoirfor in situ combustion.

[0028] U.S. Pat. No. 2,780,450 to Ljungstrom describes heatingbituminous geological formations in situ to convert or crack a liquidtar-like substance into oils and gases.

[0029] U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

[0030] U.S. Pat. No. 5,046,559 to Glandt and 5,060,726 to Glandt et al.,which are incorporated by reference as if fully set forth herein,describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

[0031] Substantial reserves of heavy hydrocarbons are known to exist informations that have relatively low permeability. For example, billionsof barrels of oil reserves are known to exist in diatomaceous formationsin California. Several methods have been proposed and/or used forproducing heavy hydrocarbons from relatively low permeabilityformations.

[0032] U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporatedby reference as if fully set forth herein, describes a method forrecovering hydrocarbons (e.g., oil) from a low permeability subterraneanreservoir of the type comprised primarily of diatomite. A first slug orvolume of a heated fluid (e.g., 60% quality steam) is injected into thereservoir at a pressure greater than the fracturing pressure of thereservoir. The well is then shut in and the reservoir is allowed to soakfor a prescribed period (e.g., 10 days or more) to allow the oil to bedisplaced by the steam into the fractures. The well is then produceduntil the production rate drops below an economical level. A second slugof steam is then injected and the cycles are repeated.

[0033] U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporatedby reference as if fully set forth herein, describes a method for therecovery of viscous oil from a subterranean, viscous oil-containingformation by injecting steam into the formation.

[0034] U.S. Pat. No. 5,339,897 to Leaute describes a method andapparatus for recovering and/or upgrading hydrocarbons utilizing in situcombustion and horizontal wells.

[0035] U.S. Pat. No. 5,431,224 to Laali, which is incorporated byreference as if fully set forth herein, describes a method for improvinghydrocarbon flow from low permeability tight reservoir rock.

[0036] U.S. Pat. Nos. 5,297,626 Vinegar et al. and 5,392,854 to Vinegaret al., which are incorporated by reference as if fully set forthherein, describe a process wherein an oil containing subterraneanformation is heated. The following patents are incorporated herein byreference: U.S. Pat. Nos. 6,152,987 to Ma et al.; 5,525,322 to Willms;5,861,137 to Edlund; and 5,229,102 to Minet et al.

[0037] As outlined above, there has been a significant amount of effortto develop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

[0038] U.S. Pat. No. RE36,569 to Kuckes, which is incorporated byreference as if fully set forth herein, describes a method fordetermining distance from a borehole to a nearby, substantially paralleltarget well for use in guiding the drilling of the borehole. The methodincludes positioning a magnetic field sensor in the borehole at a knowndepth and providing a magnetic field source in the target well.

[0039] U.S. Pat. Nos. 5,515,931 to Kuckes and 5,657,826 to Kuckes, whichare incorporated by reference as if fully set forth herein, describesingle guide wire systems for use in directional drilling of boreholes.The systems include a guide wire extending generally parallel to thedesired path of the borehole.

[0040] U.S. Pat. No. 5,725,059 to Kuckes et al., which is incorporatedby reference as if fully set forth herein, describes a method andapparatus for steering boreholes for use in creating a subsurfacebarrier layer. The method includes drilling a first reference borehole,retracting the drill stem while injecting a sealing material into theearth around the borehole, and simultaneously pulling a guide wire intothe borehole. The guide wire is used to produce a corresponding magneticfield in the earth around the reference borehole. The vector componentsof the magnetic field are used to determine the distance and directionfrom the borehole being drilled to the reference borehole in order tosteer the borehole being drilled. U.S. Pat. Nos. 5,512,830 to Kuckes;5,676,212 to Kuckes; 5,541,517 to Hartmann et al.; 5,589,775 to Kuckes;5,787,997 to Hartmann; and 5,923,170 to Kuckes, each of which isincorporated by reference as if fully set forth herein, describe methodsfor measurement of the distance and direction between boreholes usingmagnetic or electromagnetic fields.

SUMMARY OF THE INVENTION

[0041] In an embodiment, hydrocarbons within a hydrocarbon containingformation (e.g., a formation containing coal, oil shale, heavyhydrocarbons, or a combination thereof) may be converted in situ withinthe formation to yield a mixture of relatively high quality hydrocarbonproducts, hydrogen, and/or other products. One or more heat sources maybe used to heat a portion of the hydrocarbon containing formation totemperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons,hydrogen, and other formation fluids may be removed from the formationthrough one or more production wells. In some embodiments, formationfluids may be removed in a vapor phase. In other embodiments, formationfluids may be removed in liquid and vapor phases or in a liquid phase.Temperature and pressure in at least a portion of the formation may becontrolled during pyrolysis to yield improved products from theformation.

[0042] In an embodiment, one or more heat sources may be installed intoa formation to heat the formation. Heat sources may be installed bydrilling openings (well bores) into the formation. In some embodiments,openings may be formed in the formation using a drill with a steerablemotor and an accelerometer. Alternatively, an opening may be formed intothe formation by geosteered drilling. Alternately, an opening may beformed into the formation by sonic drilling.

[0043] One or more heat sources may be disposed within the opening suchthat the heat sources transfer heat to the formation. For example, aheat source may be placed in an open wellbore in the formation. Heat mayconductively and radiatively transfer from the heat source to theformation. Alternatively, a heat source may be placed within a heaterwell that may be packed with gravel, sand, and/or cement. The cement maybe a refractory cement.

[0044] In some embodiments, one or more heat sources may be placed in apattern within the formation. For example, in one embodiment, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation with an array of heatsources disposed within the formation. In some embodiments, the array ofheat sources can be positioned substantially equidistant from aproduction well. Certain patterns (e.g., triangular arrays, hexagonalarrays, or other array patterns) may be more desirable for specificapplications. In addition, the array of heat sources may be disposedsuch that a distance between each heat source may be less than about 70feet (21 m). In addition, the in situ conversion process forhydrocarbons may include heating at least a portion of the formationwith heat sources disposed substantially parallel to a boundary of thehydrocarbons. Regardless of the arrangement of or distance between theheat sources, in certain embodiments, a ratio of heat sources toproduction wells disposed within a formation may be greater than about3, 5, 8, 10, 20, or more.

[0045] Certain embodiments may also include allowing heat to transferfrom one or more of the heat sources to a selected section of the heatedportion. In an embodiment, the selected section may be disposed betweenone or more heat sources. For example, the in situ conversion processmay also include allowing heat to transfer from one or more heat sourcesto a selected section of the formation such that heat from one or moreof the heat sources pyrolyzes at least some hydrocarbons within theselected section. The in situ conversion process may include heating atleast a portion of a hydrocarbon containing formation above apyrolyzation temperature of hydrocarbons in the formation. For example,a pyrolyzation temperature may include a temperature of at least about270° C. Heat may be allowed to transfer from one or more of the heatsources to the selected section substantially by conduction.

[0046] One or more heat sources may be located within the formation suchthat superposition of heat produced from one or more heat sources mayoccur. Superposition of heat may increase a temperature of the selectedsection to a temperature sufficient for pyrolysis of at least some ofthe hydrocarbons within the selected section. Superposition of heat mayvary depending on, for example, a spacing between heat sources. Thespacing between heat sources may be selected to optimize heating of thesection selected for treatment. Therefore, hydrocarbons may be pyrolyzedwithin a larger area of the portion. Spacing between heat sources may beselected to increase the effectiveness of the heat sources, therebyincreasing the economic viability of a selected in situ conversionprocess for hydrocarbons. Superposition of heat tends to increase theuniformity of heat distribution in the section of the formation selectedfor treatment.

[0047] Various systems and methods may be used to provide heat sources.In an embodiment, a natural distributed combustor system and method mayheat at least a portion of a hydrocarbon containing formation. Thesystem and method may first include heating a first portion of theformation to a temperature sufficient to support oxidation of at leastsome of the hydrocarbons therein. One or more conduits may be disposedwithin one or more openings. One or more of the conduits may provide anoxidizing fluid from an oxidizing fluid source into an opening in theformation. The oxidizing fluid may oxidize at least a portion of thehydrocarbons at a reaction zone within the formation. Oxidation maygenerate heat at the reaction zone. The generated heat may transfer fromthe reaction zone to a pyrolysis zone in the formation. The heat maytransfer by conduction, radiation, and/or convection. A heated portionof the formation may include the reaction zone and the pyrolysis zone.The heated portion may also be located adjacent to the opening. One ormore of the conduits may remove one or more oxidation products from thereaction zone and/or the opening in the formation. Alternatively,additional conduits may remove one or more oxidation products from thereaction zone and/or formation.

[0048] In certain embodiments, the flow of oxidizing fluid may becontrolled along at least a portion of the length of the reaction zone.In some embodiments, hydrogen may be allowed to transfer into thereaction zone.

[0049] In an embodiment, a natural distributed combustor may include asecond conduit. The second conduit may remove an oxidation product fromthe formation. The second conduit may remove an oxidation product tomaintain a substantially constant temperature in the formation. Thesecond conduit may control the concentration of oxygen in the openingsuch that the oxygen concentration is substantially constant. The firstconduit may include orifices that direct oxidizing fluid in a directionsubstantially opposite a direction oxidation products are removed withorifices on the second conduit. The second conduit may have a greaterconcentration of orifices toward an upper end of the second conduit. Thesecond conduit may allow heat from the oxidation product to transfer tothe oxidizing fluid in the first conduit. The pressure of the fluidswithin the first and second conduits may be controlled such that aconcentration of the oxidizing fluid along the length of the firstconduit is substantially uniform.

[0050] In an embodiment, a system and a method may include an opening inthe formation extending from a first location on the surface of theearth to a second location on the surface of the earth. For example, theopening may be substantially U-shaped. Heat sources may be placed withinthe opening to provide heat to at least a portion of the formation.

[0051] A conduit may be positioned in the opening extending from thefirst location to the second location. In an embodiment, a heat sourcemay be positioned proximate and/or in the conduit to provide heat to theconduit. Transfer of the heat through the conduit may provide heat to aselected section of the formation. In some embodiments, an additionalheater may be placed in an additional conduit to provide heat to theselected section of the formation through the additional conduit.

[0052] In some embodiments, an annulus is formed between a wall of theopening and a wall of the conduit placed within the opening extendingfrom the first location to the second location. A heat source may beplace proximate and/or in the annulus to provide heat to a portion theopening. The provided heat may transfer through the annulus to aselected section of the formation.

[0053] In an embodiment, a system and method for heating a hydrocarboncontaining formation may include one or more insulated conductorsdisposed in one or more openings in the formation. The openings may beuncased. Alternatively, the openings may include a casing. As such, theinsulated conductors may provide conductive, radiant, or convective heatto at least a portion of the formation. In addition, the system andmethod may allow heat to transfer from the insulated conductor to asection of the formation. In some embodiments, the insulated conductormay include a copper-nickel alloy. In some embodiments, the insulatedconductor may be electrically coupled to two additional insulatedconductors in a 3-phase Y configuration.

[0054] An embodiment of a system and method for heating a hydrocarboncontaining formation may include a conductor placed within a conduit(e.g., a conductor-in-conduit heat source). The conduit may be disposedwithin the opening. An electric current may be applied to the conductorto provide heat to a portion of the formation. The system may allow heatto transfer from the conductor to a section of the formation during use.In some embodiments, an oxidizing fluid source may be placed proximatean opening in the formation extending from the first location on theearth's surface to the second location on the earth's surface. Theoxidizing fluid source may provide oxidizing fluid to a conduit in theopening. The oxidizing fluid may transfer from the conduit to a reactionzone in the formation. In an embodiment, an electrical current may beprovided to the conduit to heat a portion of the conduit. The heat maytransfer to the reaction zone in the hydrocarbon containing formation.Oxidizing fluid may then be provided to the conduit. The oxidizing fluidmay oxidize hydrocarbons in the reaction zone, thereby generating heat.The generated heat may transfer to a pyrolysis zone and the transferredheat may pyrolyze hydrocarbons within the pyrolysis zone.

[0055] In some embodiments, an insulation layer may be coupled to aportion of the conductor. The insulation layer may electrically insulateat least a portion of the conductor from the conduit during use.

[0056] In an embodiment, a conductor-in-conduit heat source having adesired length may be assembled. A conductor may be placed within theconduit to form the conductor-in-conduit heat source. Two or moreconductor-in-conduit heat sources may be coupled together to form a heatsource having the desired length. The conductors of theconductor-in-conduit heat sources may be electrically coupled together.In addition, the conduits may be electrically coupled together. Adesired length of the conductor-in-conduit may be placed in an openingin the hydrocarbon containing formation. In some embodiments, individualsections of the conductor-in-conduit heat source may be coupled usingshielded active gas welding.

[0057] In some embodiments, a centralizer may be used to inhibitmovement of the conductor within the conduit. A centralizer may beplaced on the conductor as a heat source is made. In certainembodiments, a protrusion may be placed on the conductor to maintain thelocation of a centralizer.

[0058] In certain embodiments, a heat source of a desired length may beassembled proximate the hydrocarbon containing formation. The assembledheat source may then be coiled. The heat source may be placed in thehydrocarbon containing formation by uncoiling the heat source into theopening in the hydrocarbon containing formation.

[0059] In certain embodiments, portions of the conductors may include anelectrically conductive material. Use of the electrically conductivematerial on a portion (e.g., in the overburden portion) of the conductormay lower an electrical resistance of the conductor.

[0060] A conductor placed in a conduit may be treated to increase theemissivity of the conductor, in some embodiments. The emissivity of theconductor may be increased by roughening at least a portion of thesurface of the conductor. In certain embodiments, the conductor may betreated to increase the emissivity prior to being placed within theconduit. In some embodiments, the conduit may be treated to increase theemissivity of the conduit.

[0061] In an embodiment, a system and method may include one or moreelongated members disposed in an opening in the formation. Each of theelongated members may provide heat to at least a portion of theformation. One or more conduits may be disposed in the opening. One ormore of the conduits may provide an oxidizing fluid from an oxidizingfluid source into the opening. In certain embodiments, the oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmember.

[0062] In certain embodiments, an expansion mechanism may be coupled toa heat source. The expansion mechanism may allow the heat source to moveduring use. For example, the expansion mechanism may allow for theexpansion of the heat source during use.

[0063] In one embodiment, an in situ method and system for heating ahydrocarbon containing formation may include providing oxidizing fluidto a first oxidizer placed in an opening in the formation. Fuel may beprovided to the first oxidizer and at least some fuel may be oxidized inthe first oxidizer. Oxidizing fluid may be provided to a second oxidizerplaced in the opening in the formation. Fuel may be provided to thesecond oxidizer and at least some fuel may be oxidized in the secondoxidizer. Heat from oxidation of fuel may be allowed to transfer to aportion of the formation.

[0064] An opening in a hydrocarbon containing formation may include afirst elongated portion, a second elongated portion, and a thirdelongated portion. Certain embodiments of a method and system forheating a hydrocarbon containing formation may include providing heatfrom a first heater placed in the second elongated portion. The secondelongated portion may diverge from the first elongated portion in afirst direction. The third elongated portion may diverge from the firstelongated portion in a second direction. The first direction may besubstantially different than the second direction. Heat may be providedfrom a second heater placed in the third elongated portion of theopening in the formation. Heat from the first heater and the secondheater may be allowed to transfer to a portion of the formation.

[0065] An embodiment of a method and system for heating a hydrocarboncontaining formation may include providing oxidizing fluid to a firstoxidizer placed in an opening in the formation. Fuel may be provided tothe first oxidizer and at least some fuel may be oxidized in the firstoxidizer. The method may further include allowing heat from oxidation offuel to transfer to a portion of the formation and allowing heat totransfer from a heater placed in the opening to a portion of theformation.

[0066] In an embodiment, a system and method for heating a hydrocarboncontaining formation may include oxidizing a fuel fluid in a heater. Themethod may further include providing at least a portion of the oxidizedfuel fluid into a conduit disposed in an opening in the formation. Inaddition, additional heat may be transferred from an electric heaterdisposed in the opening to the section of the formation. Heat may beallowed to transfer uniformly along a length of the opening.

[0067] Energy input costs may be reduced in some embodiments of systemsand methods described above. For example, an energy input cost may bereduced by heating a portion of a hydrocarbon containing formation byoxidation in combination with heating the portion of the formation by anelectric heater. The electric heater may be turned down and/or off whenthe oxidation reaction begins to provide sufficient heat to theformation. Electrical energy costs associated with heating at least aportion of a formation with an electric heater may be reduced. Thus, amore economical process may be provided for heating a hydrocarboncontaining formation in comparison to heating by a conventional method.In addition, the oxidation reaction may be propagated slowly through agreater portion of the formation such that fewer heat sources may berequired to heat such a greater portion in comparison to heating by aconventional method.

[0068] Certain embodiments as described herein may provide a lower costsystem and method for heating a hydrocarbon containing formation. Forexample, certain embodiments may more uniformly transfer heat along alength of a heater. Such a length of a heater may be greater than about300 m or possibly greater than about 600 m. In addition, in certainembodiments, heat may be provided to the formation more efficiently byradiation. Furthermore, certain embodiments of systems may have asubstantially longer lifetime than presently available systems.

[0069] In an embodiment, an in situ conversion system and method forhydrocarbons may include maintaining a portion of the formation in asubstantially unheated condition. The portion may provide structuralstrength to the formation and/or confinement/isolation to certainregions of the formation. A processed hydrocarbon containing formationmay have alternating heated and substantially unheated portions arrangedin a pattern that may, in some embodiments, resemble a checkerboardpattern, or a pattern of alternating areas (e.g., strips) of heated andunheated portions.

[0070] In an embodiment, a heat source may advantageously heat onlyalong a selected portion or selected portions of a length of the heater.For example, a formation may include several hydrocarbon containinglayers. One or more of the hydrocarbon containing layers may beseparated by layers containing little or no hydrocarbons. A heat sourcemay include several discrete high heating zones that may be separated bylow heating zones. The high heating zones may be disposed proximatehydrocarbon containing layers such that the layers may be heated. Thelow heating zones may be disposed proximate layers containing little orno hydrocarbons such that the layers may not be substantially heated.For example, an electric heater may include one or more low resistanceheater sections and one or more high resistance heater sections. Lowresistance heater sections of the electric heater may be disposed inand/or proximate layers containing little or no hydrocarbons. Inaddition, high resistance heater sections of the electric heater may bedisposed proximate hydrocarbon containing layers. In an additionalexample, a fueled heater (e.g., surface burner) may include insulatedsections. Insulated sections of the fueled heater may be placedproximate or adjacent to layers containing little or no hydrocarbons.Alternately, a heater with distributed air and/or fuel may be configuredsuch that little or no fuel may be combusted proximate or adjacent tolayers containing little or no hydrocarbons. Such a fueled heater mayinclude flameless combustors and natural distributed combustors.

[0071] In certain embodiments, the permeability of a hydrocarboncontaining formation may vary within the formation. For example, a firstsection may have a lower permeability than a second section. In anembodiment, heat may be provided to the formation to pyrolyzehydrocarbons within the lower permeability first section. Pyrolysisproducts may be produced from the higher permeability second section ina mixture of hydrocarbons.

[0072] In an embodiment, a heating rate of the formation may be slowlyraised through the pyrolysis temperature range. For example, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation to raise an averagetemperature of the portion above about 270° C. by a rate less than aselected amount (e.g., about 10° C., 5° C., 3° C., 1° C., 0.5° C., or0.1 C.) per day. In a further embodiment, the portion may be heated suchthat an average temperature of the selected section may be less thanabout 375° C. or, in some embodiments, less than about 400° C.

[0073] In an embodiment, a temperature of the portion may be monitoredthrough a test well disposed in a formation. For example, the test wellmay be positioned in a formation between a first heat source and asecond heat source. Certain systems and methods may include controllingthe heat from the first heat source and/or the second heat source toraise the monitored temperature at the test well at a rate of less thanabout a selected amount per day. In addition or alternatively, atemperature of the portion may be monitored at a production well. An insitu conversion process for hydrocarbons may include controlling theheat from the first heat source and/or the second heat source to raisethe monitored temperature at the production well at a rate of less thana selected amount per day.

[0074] An embodiment of an in situ method of measuring a temperaturewithin a wellbore may include providing a pressure wave from a pressurewave source into the wellbore. The wellbore may include a plurality ofdiscontinuities along a length of the wellbore. The method furtherincludes measuring a reflection signal of the pressure wave and usingthe reflection signal to assess at least one temperature between atleast two discontinuities.

[0075] Certain embodiments may include heating a selected volume of ahydrocarbon containing formation. Heat may be provided to the selectedvolume by providing power to one or more heat sources. Power may bedefined as heating energy per day provided to the selected volume. Apower (Pwr) required to generate a heating rate (h, in units of, forexample, ° C./day) in a selected volume (V) of a hydrocarbon containingformation may be determined by EQN. 1:

Pwr=h*V*C _(v)*ρ_(B).  (1)

[0076] In this equation, an average heat capacity of the formation(C_(v)) and an average bulk density of the formation (ρB) may beestimated or determined using one or more samples taken from thehydrocarbon containing formation.

[0077] Certain embodiments may include raising and maintaining apressure in a hydrocarbon containing formation. Pressure may be, forexample, controlled within a range of about 2 bars absolute to about 20bars absolute. For example, the process may include controlling apressure within a majority of a selected section of a heated portion ofthe formation. The controlled pressure may be above about 2 barsabsolute during pyrolysis. In some embodiments, an in situ conversionprocess for hydrocarbons may include raising and maintaining thepressure in the formation within a range of about 20 bars absolute toabout 36 bars absolute.

[0078] In an embodiment, compositions and properties of formation fluidsproduced by an in situ conversion process for hydrocarbons may varydepending on, for example, conditions within a hydrocarbon containingformation.

[0079] Certain embodiments may include controlling the heat provided toat least a portion of the formation such that production of lessdesirable products in the portion may be inhibited. Controlling the heatprovided to at least a portion of the formation may also increase theuniformity of permeability within the formation. For example,controlling the heating of the formation to inhibit production of lessdesirable products may, in some embodiments, include controlling theheating rate to less than a selected amount (e.g., 10° C., 5° C., 3° C.,1° C., 0.5° C., or 0.1° C.) per day.

[0080] Controlling pressure, heat and/or heating rates of a selectedsection in a formation may increase production of selected formationfluids. For example, the amount and/or rate of heating may be controlledto produce formation fluids having an American Petroleum Institute(“API”) gravity greater than about 25°. Heat and/or pressure may becontrolled to inhibit production of olefins in the produced fluids.

[0081] Controlling formation conditions to control the pressure ofhydrogen in the produced fluid may result in improved qualities of theproduced fluids. In some embodiments, it may be desirable to controlformation conditions so that the partial pressure of hydrogen in aproduced fluid is greater than about 0.5 bars absolute, as measured at aproduction well.

[0082] In one embodiment, a method of treating a hydrocarbon containingformation in situ may include adding hydrogen to the selected sectionafter a temperature of the selected section is at least about 270° C.Other embodiments may include controlling a temperature of the formationby selectively adding hydrogen to the formation.

[0083] In certain embodiments, a hydrocarbon containing formation may betreated in situ with a heat transfer fluid such as steam. In anembodiment, a method of formation may include injecting a heat transferfluid into a formation. Heat from the heat transfer fluid may transferto a selected section of the formation. The heat from the heat transferfluid may pyrolyze a substantial portion of the hydrocarbons within theselected section of the formation. The produced gas mixture may includehydrocarbons with an average API gravity greater than about 25°.

[0084] Furthermore, treating a hydrocarbon containing formation with aheat transfer fluid may also mobilize hydrocarbons in the formation. Inan embodiment, a method of treating a formation may include injecting aheat transfer fluid into a formation, allowing the heat from the heattransfer fluid to transfer to a selected first section of the formation,and mobilizing and pyrolyzing at least some of the hydrocarbons withinthe selected first section of the formation. At least some of themobilized hydrocarbons may flow from the selected first section of theformation to a selected second section of the formation. The heat maypyrolyze at least some of the hydrocarbons within the selected secondsection of the formation. A gas mixture may be produced from theformation.

[0085] Another embodiment of treating a formation with a heat transferfluid may include a moving heat transfer fluid front. A method mayinclude injecting a heat transfer fluid into a formation and allowingthe heat transfer fluid to migrate through the formation. A size of aselected section may increase as a heat transfer fluid front migratesthrough an untreated portion of the formation. The selected section is aportion of the formation treated by the heat transfer fluid. Heat fromthe heat transfer fluid may transfer heat to the selected section. Theheat may pyrolyze at least some of the hydrocarbons within the selectedsection of the formation. The heat may also mobilize at least some ofthe hydrocarbons at the heat transfer fluid front. The mobilizedhydrocarbons may flow substantially parallel to the heat transfer fluidfront. The heat may pyrolyze at least a portion of the hydrocarbons inthe mobilized fluid and a gas mixture may be produced from theformation.

[0086] Simulations may be utilized to increase an understanding of insitu processes. Simulations may model heating of the formation from heatsources and the transfer of heat to a selected section of the formation.Simulations may require the input of model parameters, properties of theformation, operating conditions, process characteristics, and/or desiredparameters to determine operating conditions. Simulations may assessvarious aspects of an in situ process. For example, various aspects mayinclude, but not be limited to, deformation characteristics, heatingrates, temperatures within the formation, pressures, time to firstproduced fluids, and/or compositions of produced fluids.

[0087] Systems utilized in conducting simulations may include a centralprocessing unit (CPU), a data memory, and a system memory. The systemmemory and the data memory may be coupled to the CPU. Computer programsexecutable to implement simulations may be stored on the system memory.Carrier mediums may include program instructions that arecomputer-executable to simulate the in situ processes.

[0088] In one embodiment, a computer-implemented method and system oftreating a hydrocarbon containing formation may include providing to acomputational system at least one set of operating conditions of an insitu system being used to apply heat to a formation. The in situ systemmay include at least one heat source. The method may further includeproviding to the computational system at least one desired parameter forthe in situ system. The computational system may be used to determine atleast one additional operating condition of the formation to achieve thedesired parameter.

[0089] In an embodiment, operating conditions may be determined bymeasuring at least one property of the formation. At least one measuredproperty may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to determine a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The determined set of operating conditions mayincrease production of selected formation fluids from the formation.

[0090] In some embodiments, a property of the formation and an operatingcondition used in the in situ process may be provided to a computersystem to model the in situ process to determine a processcharacteristic.

[0091] In an embodiment, a heat input rate for an in situ process fromtwo or more heat sources may be simulated on a computer system. Adesired parameter of the in situ process may be provided to thesimulation. The heat input rate from the heat sources may be controlledto achieve the desired parameter.

[0092] Alternatively, a heat input property may be provided to acomputer system to assess heat injection rate data using a simulation.In addition, a property of the formation may be provided to the computersystem. The property and the heat injection rate data may be utilized bya second simulation to determine a process characteristic for the insitu process as a function of time.

[0093] Values for the model parameters may be adjusted using processcharacteristics from a series of simulations. The model parameters maybe adjusted such that the simulated process characteristics correspondto process characteristics in situ. After the model parameters have beenmodified to correspond to the in situ process, a process characteristicor a set of process characteristics based on the modified modelparameters may be determined. In certain embodiments, multiplesimulations may be run such that the simulated process characteristicscorrespond to the process characteristics in situ.

[0094] In some embodiments, operating conditions may be supplied to asimulation to assess a process characteristic. Additionally, a desiredvalue of a process characteristic for the in situ process may beprovided to the simulation to assess an operating condition that yieldsthe desired value.

[0095] In certain embodiments, databases in memory on a computer may beused to store relationships between model parameters, properties of theformation, operating conditions, process characteristics, desiredparameters, etc. These databases may be accessed by the simulations toobtain inputs. For example, after desired values of processcharacteristics are provided to simulations, an operating condition maybe assessed to achieve the desired values using these databases.

[0096] In some embodiments, computer systems may utilize inputs in asimulation to assess information about the in situ process. In someembodiments, the assessed information may be used to operate the in situprocess. Alternatively, the assessed information and a desired parametermay be provided to a second simulation to obtain information. Thisobtained information may be used to operate the in situ process.

[0097] In an embodiment, a method of modeling may include simulating oneor more stages of the in situ process. Operating conditions from the oneor more stages may be provided to a simulation to assess a processcharacteristic of the one or more stages.

[0098] In an embodiment, operating conditions may be assessed bymeasuring at least one property of the formation. At least the measuredproperties may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to assess a set of operating conditions from at least theone or more measured properties. The program may also determine the setof operating conditions from at least one property of the selectedformation fluids. The assessed set of operating conditions may increaseproduction of selected formation fluids from the formation.

[0099] In one embodiment, a method for controlling an in situ system oftreating a hydrocarbon containing formation may include monitoring atleast one acoustic event within the formation using at least oneacoustic detector placed within a wellbore in the formation. At leastone acoustic event may be recorded with an acoustic monitoring system.The method may also include analyzing the at least one acoustic event todetermine at least one property of the formation. The in situ system maybe controlled based on the analysis of the at least one acoustic event.

[0100] An embodiment of a method of determining a heating rate fortreating a hydrocarbon containing formation in situ may includeconducting an experiment at a relatively constant heating rate. Theresults of the experiment may be used to determine a heating rate fortreating the formation in situ. The determined heating rate may be usedto determine a well spacing in the formation.

[0101] In an embodiment, a method of predicting characteristics of aformation fluid may include determining an isothermal heatingtemperature that corresponds to a selected heating rate for theformation. The determined isothermal temperature may be used in anexperiment to determine at least one product characteristic of theformation fluid produced from the formation for the selected heatingrate. Certain embodiments may include altering a composition offormation fluids produced from a hydrocarbon containing formation byaltering a location of a production well with respect to a heater well.For example, a production well may be located with respect to a heaterwell such that a non-condensable gas fraction of produced hydrocarbonfluids may be larger than a condensable gas fraction of the producedhydrocarbon fluids.

[0102] Condensable hydrocarbons produced from the formation willtypically include paraffins, cycloalkanes, mono-aromatics, anddi-aromatics as major components. Such condensable hydrocarbons may alsoinclude other components such as tri-aromatics, etc.

[0103] In certain embodiments, a majority of the hydrocarbons inproduced fluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. In otherembodiments, fluid produced may have a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, of greater thanapproximately 1 (e.g., for oil shale and heavy hydrocarbons) or greaterthan approximately 0.3 (e.g., for coal). The non-condensablehydrocarbons may include, but are not limited to, hydrocarbons havingcarbon numbers less than 5.

[0104] In certain embodiments, the API gravity of the hydrocarbons inproduced-fluid may be approximately 25° or above (e.g., 30°, 40°, 50°,etc.). In certain embodiments, the hydrogen to carbon atomic ratio inproduced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

[0105] In certain embodiments, (e.g., when the formation includes coal)fluid produced from a formation may include oxygenated hydrocarbons. Inan example, the condensable hydrocarbons may include an amount ofoxygenated hydrocarbons greater than about 5 weight % of the condensablehydrocarbons.

[0106] Condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the condensable hydrocarbonsmay be from about 0.1 weight % to about 15 weight %. Alternatively, theolefin content of the condensable hydrocarbons may be from about 0.1weight % to about 2.5 weight % or, in some embodiments, less than about5 weight %.

[0107] Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the non-condensablehydrocarbons may be gauged using the ethene/ethane molar ratio. Incertain embodiments, the ethene/ethane molar ratio may range from about0.001 to about 0.15.

[0108] Fluid produced from the formation may include aromatic compounds.For example, the condensable hydrocarbons may include an amount ofaromatic compounds greater than about 20 weight % or about 25 weight %of the condensable hydrocarbons. The condensable hydrocarbons may alsoinclude relatively low amounts of compounds with more than two rings inthem (e.g., tri-aromatics or above). For example, the condensablehydrocarbons may include less than about 1 weight %, 2 weight %, orabout 5 weight % of tri-aromatics or above in the condensablehydrocarbons.

[0109] In particular, in certain embodiments, asphaltenes (i.e., largemulti-ring aromatics that are substantially insoluble in hydrocarbons)make up less than about 0.1 weight % of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0 weight % to about 0.1 weight % or, in someembodiments, less than about 0.3 weight %.

[0110] Condensable hydrocarbons of a produced fluid may also includerelatively large amounts of cycloalkanes. For example, the condensablehydrocarbons may include a cycloalkane component of up to 30 weight %(e.g., from about 5 weight % to about 30 weight %) of the condensablehydrocarbons.

[0111] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is nitrogen (e.g., typically thenitrogen is in nitrogen containing compounds such as pyridines, amines,amides, etc.).

[0112] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for oil shale and heavyhydrocarbons), less than about 1 weight % (when calculated on anelemental basis) of the condensable hydrocarbons is oxygen (e.g.,typically the oxygen is in oxygen containing compounds such as phenols,substituted phenols, ketones, etc.). In certain other embodiments (e.g.,for coal) between about 5 weight % and about 30 weight % of thecondensable hydrocarbons are typically oxygen containing compounds suchas phenols, substituted phenols, ketones, etc. In some instances,certain compounds containing oxygen (e.g., phenols) may be valuable and,as such, may be economically separated from the produced fluid.

[0113] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1 weight % (when calculated on an elementalbasis) of the condensable hydrocarbons is sulfur (e.g., typically thesulfur is in sulfur containing compounds such as thiophenes, mercaptans,etc.).

[0114] Furthermore, the fluid produced from the formation may includeammonia (typically the ammonia condenses with the water, if any,produced from the formation). For example, the fluid produced from theformation may in certain embodiments include about 0.05 weight % or moreof ammonia. Certain formations may produce larger amounts of ammonia(e.g., up to about 10 weight % of the total fluid produced may beammonia).

[0115] Furthermore, a produced fluid from the formation may also includemolecular hydrogen (H₂), water, carbon dioxide, hydrogen sulfide, etc.For example, the fluid may include a H₂ content between about 10 volume% and about 80 volume % of the non-condensable hydrocarbons.

[0116] Certain embodiments may include heating to yield at least about15 weight % of a total organic carbon content of at least some of thehydrocarbon containing formation into formation fluids.

[0117] In an embodiment, an in situ conversion process for treating ahydrocarbon containing formation may include providing heat to a sectionof the formation to yield greater than about 60 weight % of thepotential hydrocarbon products and hydrogen, as measured by the FischerAssay.

[0118] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation.

[0119] Formation fluids produced from a section of the formation maycontain one or more components that may be separated from the formationfluids. In addition, conditions within the formation may be controlledto increase production of a desired component.

[0120] In certain embodiments, a method of converting pyrolysis fluidsinto olefins may include converting formation fluids into olefins. Anembodiment may include separating olefins from fluids produced from aformation.

[0121] In an embodiment, a method of enhancing phenol production from ahydrocarbon containing formation in situ may include controlling atleast one condition within at least a portion of the formation toenhance production of phenols in formation fluid. In other embodiments,production of phenols from a hydrocarbon containing formation may becontrolled by converting at least a portion of formation fluid intophenols. Furthermore, phenols may be separated from fluids produced froma hydrocarbon containing formation.

[0122] An embodiment of a method of enhancing BTEX compounds (i.e.,benzene, toluene, ethylbenzene, and xylene compounds) produced in situin a hydrocarbon containing formation may include controlling at leastone condition within a portion of the formation to enhance production ofBTEX compounds in formation fluid. In another embodiment, a method mayinclude separating at least a portion of the BTEX compounds from theformation fluid. In addition, the BTEX compounds may be separated fromthe formation fluids after the formation fluids are produced. In otherembodiments, at least a portion of the produced formation fluids may beconverted into BTEX compounds.

[0123] In one embodiment, a method of enhancing naphthalene productionfrom a hydrocarbon containing formation in situ may include controllingat least one condition within at least a portion of the formation toenhance production of naphthalene in formation fluid. In anotherembodiment, naphthalene may be separated from produced formation fluids.

[0124] Certain embodiments of a method of enhancing anthraceneproduction from a hydrocarbon containing formation in situ may includecontrolling at least one condition within at least a portion of theformation to enhance production of anthracene in formation fluid. In anembodiment, anthracene may be separated from produced formation fluids.

[0125] In one embodiment, a method of separating ammonia from fluidsproduced from a hydrocarbon containing formation in situ may includeseparating at least a portion of the ammonia from the produced fluid.Furthermore, an embodiment of a method of generating ammonia from fluidsproduced from a formation may include hydrotreating at least a portionof the produced fluids to generate ammonia.

[0126] In an embodiment, a method of enhancing pyridines production froma hydrocarbon containing formation in situ may include controlling atleast one condition within at least a portion of the formation toenhance production of pyridines in formation fluid. Additionally,pyridines may be separated from produced formation fluids.

[0127] In certain embodiments, a method of selecting a hydrocarboncontaining formation to be treated in situ such that production ofpyridines is enhanced may include examining pyridines concentrations ina plurality of samples from hydrocarbon containing formations. Themethod may further include selecting a formation for treatment at leastpartially based on the pyridines concentrations. Consequently, theproduction of pyridines to be produced from the formation may beenhanced.

[0128] In an embodiment, a method of enhancing pyrroles production froma hydrocarbon containing formation in situ may include controlling atleast one condition within at least a portion of the formation toenhance production of pyrroles in formation fluid. In addition, pyrrolesmay be separated from produced formation fluids.

[0129] In certain embodiments, a hydrocarbon containing formation to betreated in situ may be selected such that production of pyrroles isenhanced. The method may include examining pyrroles concentrations in aplurality of samples from hydrocarbon containing formations. Theformation may be selected for treatment at least partially based on thepyrroles concentrations, thereby enhancing the production of pyrroles tobe produced from such formation.

[0130] In one embodiment, thiophenes production a hydrocarbon containingformation in situ may be enhanced by controlling at least one conditionwithin at least a portion of the formation to enhance production ofthiophenes in formation fluid. Additionally, the thiophenes may beseparated from produced formation fluids.

[0131] An embodiment of a method of selecting a hydrocarbon containingformation to be treated in situ such that production of thiophenes isenhanced may include examining thiophenes concentrations in a pluralityof samples from hydrocarbon containing formations. The method mayfurther include selecting a formation for treatment at least partiallybased on the thiophenes concentrations, thereby enhancing the productionof thiophenes from such formations.

[0132] Certain embodiments may include providing a reducing agent to atleast a portion of the formation. A reducing agent provided to a portionof the formation during heating may increase production of selectedformation fluids. A reducing agent may include, but is not limited to,molecular hydrogen. For example, pyrolyzing at least some hydrocarbonsin a hydrocarbon containing formation may include forming hydrocarbonfragments. Such hydrocarbon fragments may react with each other andother compounds present in the formation. Reaction of these hydrocarbonfragments may increase production of olefin and aromatic compounds fromthe formation. Therefore, a reducing agent provided to the formation mayreact with hydrocarbon fragments to form selected products and/orinhibit the production of non-selected products.

[0133] In an embodiment, a hydrogenation reaction between a reducingagent provided to a hydrocarbon containing formation and at least someof the hydrocarbons within the formation may generate heat. Thegenerated heat may be allowed to transfer such that at least a portionof the formation may be heated. A reducing agent such as molecularhydrogen may also be autogenously generated within a portion of ahydrocarbon containing formation during an in situ conversion processfor hydrocarbons. The autogenously generated molecular hydrogen mayhydrogenate formation fluids within the formation. Allowing formationwaters to contact hot carbon in the spent formation may generatemolecular hydrogen. Cracking an injected hydrocarbon fluid may alsogenerate molecular hydrogen.

[0134] Certain embodiments may also include providing a fluid producedin a first portion of a hydrocarbon containing formation to a secondportion of the formation. A fluid produced in a first portion of ahydrocarbon containing formation may be used to produce a reducingenvironment in a second portion of the formation. For example, molecularhydrogen generated in a first portion of a formation may be provided toa second portion of the formation. Alternatively, at least a portion offormation fluids produced from a first portion of the formation may beprovided to a second portion of the formation to provide a reducingenvironment within the second portion.

[0135] In an embodiment, a method for hydrotreating a compound in aheated formation in situ may include controlling the H₂ partial pressurein a selected section of the formation, such that sufficient H₂ may bepresent in the selected section of the formation for hydrotreating. Themethod may further include providing a compound for hydrotreating to atleast the selected section of the formation and producing a mixture fromthe formation that includes at least some of the hydrotreated compound.

[0136] In certain embodiments, the fluids may be hydrotreated in situ ina heated formation. In situ treatment may include providing a fluid to aselected section of a formation. The in situ process may includecontrolling a H₂ partial pressure in the selected section of theformation. The H₂ partial pressure may be controlled by providinghydrogen to the part of the formation. The temperature within the partof the formation may be controlled such that the temperature remainswithin a range from about 200° C. to about 450° C. At least some of thefluid may be hydrotreated within the part of the formation. A mixtureincluding hydrotreated fluids may be produced from the formation. Theproduced mixture may include less than about 1% by weight ammonia. Theproduced mixture may include less than about 1% by weight hydrogensulfide. The produced mixture may include less than about 1% oxygenatedcompounds. The heating may be controlled such that the mixture may beproduced as a vapor.

[0137] In an embodiment, a method for hydrotreating a compound in aheated formation in situ may include controlling the H₂ partial pressurein a selected section of the formation, such that sufficient H₂ may bepresent in the selected section of the formation for hydrotreating. Themethod may further include providing a compound for hydrotreating to atleast the selected section of the formation and producing a mixture fromthe formation that includes at least some of the hydrotreated compound.

[0138] In one embodiment, a method of separating ammonia from fluidsproduced from an in situ hydrocarbon containing formation may includeseparating at least a portion of the ammonia from the produced fluid.Fluids produced from a formation may, in some embodiments, behydrotreated to generate ammonia. In certain embodiments, ammonia may beconverted to other products.

[0139] Certain embodiments may include controlling heat provided to atleast a portion of the formation such that a thermal conductivity of theportion may be increased to greater than about 0.5 W/(m ° C.) or, insome embodiments, greater than about 0.6 W/(m ° C.).

[0140] In certain embodiments, a mass of at least a portion of theformation may be reduced due, for example, to the production offormation fluids from the formation. As such, a permeability andporosity of at least a portion of the formation may increase. Inaddition, removing water during the heating may also increase thepermeability and porosity of at least a portion of the formation.

[0141] Certain embodiments may include increasing a permeability of atleast a portion of a hydrocarbon containing formation to greater thanabout 0.01, 0.1, 1, 10, 20, or 50 darcy. In addition, certainembodiments may include substantially uniformly increasing apermeability of at least a portion of a hydrocarbon containingformation. Some embodiments may include increasing a porosity of atleast a portion of a hydrocarbon containing formation substantiallyuniformly.

[0142] In situ processes may be used to produce hydrocarbons, hydrogenand other formation fluids from a relatively permeable formation thatincludes heavy hydrocarbons (e.g., from tar sands). Heating may be usedto mobilize the heavy hydrocarbons within the formation and then topyrolyze heavy hydrocarbons within the formation to form pyrolyzationfluids. Formation fluids produced during pyrolyzation may be removedfrom the formation through production wells.

[0143] In certain embodiments, fluid (e.g., gas) may be provided to arelatively permeable formation. The gas may be used to pressurize theformation. Pressure in the formation may be selected to controlmobilization of fluid within the formation. For example, a higherpressure may increase the mobilization of fluid within the formationsuch that fluids may be produced at a higher rate.

[0144] In an embodiment, a portion of a relatively permeable formationmay be heated to reduce a viscosity of the heavy hydrocarbons within theformation. The reduced viscosity heavy hydrocarbons may be mobilized.The mobilized heavy hydrocarbons may flow to a selected pyrolyzationsection of the formation. A gas may be provided into the relativelypermeable formation to increase a flow of the mobilized heavyhydrocarbons into the selected pyrolyzation section. Such a gas may be,for example, carbon dioxide. The carbon dioxide may, in someembodiments, be stored in the formation after removal of the heavyhydrocarbons. A majority of the heavy hydrocarbons within the selectedpyrolyzation section may be pyrolyzed. Pyrolyzation of the mobilizedheavy hydrocarbons may upgrade the heavy hydrocarbons to a moredesirable product. The pyrolyzed heavy hydrocarbons may be removed fromthe formation through a production well. In some embodiments, themobilized heavy hydrocarbons may be removed from the formation through aproduction well without upgrading or pyrolyzing the heavy hydrocarbons.

[0145] Hydrocarbon fluids produced from the formation may vary dependingon conditions within the formation. For example, a heating rate of aselected pyrolyzation section may be controlled to increase theproduction of selected products. In addition, pressure within theformation may be controlled to vary the composition of the producedfluids.

[0146] An embodiment of a method for producing a selected productcomposition from a relatively permeable formation containing heavyhydrocarbons in situ may include providing heat from one or more heatsources to at least one portion of the formation and allowing the heatto transfer to a selected section of the formation. The method mayfurther include producing a product from one or more of the selectedsections and blending two or more of the products to produce a producthaving about the selected product composition.

[0147] In an embodiment, heat is provided from a first set of heatsources to a first section of a hydrocarbon containing formation topyrolyze a portion of the hydrocarbons in the first section. Heat mayalso be provided from a second set of heat sources to a second sectionof the formation. The heat may reduce the viscosity of hydrocarbons inthe second section so that a portion of the hydrocarbons in the secondsection are able to move. A portion of the hydrocarbons from the secondsection may be induced to flow into the first section. A mixture ofhydrocarbons may be produced from the formation. The produced mixturemay include at least some pyrolyzed hydrocarbons.

[0148] In an embodiment, heat is provided from heat sources to a portionof a hydrocarbon containing formation. The heat may transfer from theheat sources to a selected section of the formation to decrease aviscosity of hydrocarbons within the selected section. A gas may beprovided to the selected section of the formation. The gas may displacehydrocarbons from the selected section towards a production well orproduction wells. A mixture of hydrocarbons may be produced from theselected section through the production well or production wells.

[0149] In an embodiment, a method for treating a hydrocarbon containingformation in situ may include providing heat from one or more heaters toat least a portion of the formation. The method may include allowing theheat to transfer from the one or more heaters to a part of theformation. The heat, which transfers to the part of the formation, maypyrolyze at least some of the hydrocarbons within the part of theformation. The method may include selectively limiting a temperatureproximate a selected portion of a heater wellbore. Selectively limitingthe temperature may inhibit coke formation at or near the selectedportion. The method may also include producing at least somehydrocarbons through the selected portion of the heater wellbore. Insome embodiments, a method may include producing a mixture from the partof the formation through a production well.

[0150] In certain embodiments, a quality of a produced mixture may becontrolled by varying a location for producing the mixture. The locationof production may be varied by varying the depth in the formation fromwhich fluid is produced relative to an overburden or underburden. Thelocation of production may also be varied by varying which productionwells are used to produce fluid. In some embodiments, the productionwells used to remove fluid may be chosen based on a distance of theproduction wells from activated heat sources.

[0151] In an embodiment, a blending agent may be produced from aselected section of a formation. A portion of the blending agent may bemixed with heavy hydrocarbons to produce a mixture having a selectedcharacteristic (e.g., density, viscosity, and/or stability). In certainembodiments, the heavy hydrocarbons may be produced from another sectionof the formation used to produce the blending agent. In someembodiments, the heavy hydrocarbons may be produced from anotherformation.

[0152] In some embodiments, heat may be provided to a selected sectionof a hydrocarbon containing formation to pyrolyze some hydrocarbons in alower portion of the formation. A mixture of hydrocarbons may beproduced from an upper portion of the formation. The mixture ofhydrocarbons may include at least some pyrolyzed hydrocarbons from thelower portion of the formation.

[0153] In certain embodiments, a production rate of fluid from theformation may be controlled to adjust an average time that hydrocarbonsare in, or flowing into, a pyrolysis zone or exposed to pyrolysistemperatures. Controlling the production rate may allow for productionof a large quantity of hydrocarbons of a desired quality from theformation.

[0154] Certain systems and methods may be used to treat heavyhydrocarbons in at least a portion of a relatively low permeabilityformation (e.g., in “tight” formations that contain heavy hydrocarbons).Such heavy hydrocarbons may be heated to pyrolyze at least some of theheavy hydrocarbons in a selected section of the formation. Heating mayalso increase the permeability of at least a portion of the selectedsection. Fluids generated from pyrolysis may be produced from theformation.

[0155] Certain embodiments for treating heavy hydrocarbons in arelatively low permeability formation may include providing heat fromone or more heat sources to pyrolyze some of the heavy hydrocarbons andthen to vaporize a portion of the heavy hydrocarbons. The heat sourcesmay pyrolyze at least some heavy hydrocarbons in a selected section ofthe formation and may pressurize at least a portion of the selectedsection. During the heating, the pressure within the formation mayincrease substantially. The pressure in the formation may be controlledsuch that the pressure in the formation may be maintained to produce afluid of a desired composition. Pyrolyzation fluid may be removed fromthe formation as vapor from one or more heater wells by using the backpressure created by heating the formation.

[0156] Certain embodiments for treating heavy hydrocarbons in at least aportion of a relatively low permeability formation may include heatingto create a pyrolysis zone and heating a selected second section to lessthan the average temperature within the pyrolysis zone. Heavyhydrocarbons may be pyrolyzed in the pyrolysis zone. Heating theselected second section may decrease the viscosity of some of the heavyhydrocarbons in the selected second section to create a low viscosityzone. The decrease in viscosity of the fluid in the selected secondsection may be sufficient such that at least some heated heavyhydrocarbons within the selected second section may flow into thepyrolysis zone. Pyrolyzation fluid may be produced from the pyrolysiszone. In one embodiment, the density of the heat sources in thepyrolysis zone may be greater than in the low viscosity zone.

[0157] In certain embodiments, it may be desirable to create thepyrolysis zones and low viscosity zones sequentially over time. The heatsources in a region near a desired pyrolysis zone may be activatedfirst, resulting in establishment of a substantially uniform pyrolysiszone after a period of time. Once the pyrolysis zone is established,heat sources in the low viscosity zone may be activated sequentiallyfrom nearest to farthest from the pyrolysis zone.

[0158] A heated formation may also be used to produce synthesis gas.Synthesis gas may be produced from the formation prior to or subsequentto producing a formation fluid from the formation. For example,synthesis gas generation may be commenced before and/or after formationfluid production decreases to an uneconomical level. Heat provided topyrolyze hydrocarbons within the formation may also be used to generatesynthesis gas. For example, if a portion of the formation is at atemperature from approximately 270° C. to approximately 375° C. (or 400°C. in some embodiments) after pyrolyzation, then less additional heat isgenerally required to heat such portion to a temperature sufficient tosupport synthesis gas generation.

[0159] In certain embodiments, synthesis gas is produced afterproduction of pyrolysis fluids. For example, after pyrolysis of aportion of a formation, synthesis gas may be produced from carbon and/orhydrocarbons remaining within the formation. Pyrolysis of the portionmay produce a relatively high, substantially uniform permeabilitythroughout the portion. Such a relatively high, substantially uniformpermeability may allow generation of synthesis gas from a significantportion of the formation at relatively low pressures. The portion mayalso have a large surface area and/or surface area/volume. The largesurface area may allow synthesis gas producing reactions to besubstantially at equilibrium conditions during synthesis gas generation.The relatively high, substantially uniform permeability may result in arelatively high recovery efficiency of synthesis gas, as compared tosynthesis gas generation in a hydrocarbon containing formation that hasnot been so treated.

[0160] Pyrolysis of at least some hydrocarbons may in some embodimentsconvert about 15 weight % or more of the carbon initially available.Synthesis gas generation may convert approximately up to an additional80 weight % or more of carbon initially available within the portion. Insitu production of synthesis gas from a hydrocarbon containing formationmay allow conversion of larger amounts of carbon initially availablewithin the portion. The amount of conversion achieved may, in someembodiments, be limited by subsidence concerns.

[0161] Certain embodiments may include providing heat from one or moreheat sources to heat the formation to a temperature sufficient to allowsynthesis gas generation (e.g., in a range of approximately 400° C. toapproximately 1200° C. or higher). At a lower end of the temperaturerange, generated synthesis gas may have a high hydrogen (H₂) to carbonmonoxide (CO) ratio. At an upper end of the temperature range, generatedsynthesis gas may include mostly H₂ and CO in lower ratios (e.g.,approximately a 1:1 ratio).

[0162] Heat sources for synthesis gas production may include any of theheat sources as described in any of the embodiments set forth herein.Alternatively, heating may include transferring heat from a heattransfer fluid (e.g., steam or combustion products from a burner)flowing within a plurality of wellbores within the formation.

[0163] A synthesis gas generating fluid (e.g., liquid water, steam,carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may beprovided to the formation. For example, the synthesis gas generatingfluid mixture may include steam and oxygen. In an embodiment, asynthesis gas generating fluid may include aqueous fluid produced bypyrolysis of at least some hydrocarbons within one or more otherportions of the formation. Providing the synthesis gas generating fluidmay alternatively include raising a water table of the formation toallow water to flow into it. Synthesis gas generating fluid may also beprovided through at least one injection wellbore. The synthesis gasgenerating fluid will generally react with carbon in the formation toform H₂, water, methane, CO₂, and/or CO. A portion of the carbon dioxidemay react with carbon in the formation to generate carbon monoxide.Hydrocarbons such as ethane may be added to a synthesis gas generatingfluid. When introduced into the formation, the hydrocarbons may crack toform hydrogen and/or methane. The presence of methane in producedsynthesis gas may increase the heating value of the produced. synthesisgas.

[0164] Synthesis gas generation is, in some embodiments, an endothermicprocess. Additional heat may be added to the formation during synthesisgas generation to maintain a high temperature within the formation. Theheat may be added from heater wells and/or from oxidizing carbon and/orhydrocarbons within the formation.

[0165] In an embodiment, an oxidant may be added to a synthesis gasgenerating fluid. The oxidant may include, but is not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids,or combinations thereof. The oxidant may react with carbon within theformation to exothermically generate heat. Reaction of an oxidant withcarbon in the formation may result in production of CO₂ and/or CO.Introduction of an oxidant to react with carbon in the formation mayeconomically allow raising the formation temperature high enough toresult in generation of significant quantities of H₂ and CO fromhydrocarbons within the formation. Synthesis gas generation may be via abatch process or a continuous process.

[0166] Synthesis gas may be produced from the formation through one ormore producer wells that include one or more heat sources. Such heatsources may operate to promote production of the synthesis gas with adesired composition.

[0167] Certain embodiments may include monitoring a composition of theproduced synthesis gas and then controlling heating and/or controllinginput of the synthesis gas generating fluid to maintain the compositionof the produced synthesis gas within a desired range. For example, insome embodiments (e.g., such as when the synthesis gas will be used as afeedstock for a Fischer-Tropsch process), a desired composition of theproduced synthesis gas may have a ratio of hydrogen to carbon monoxideof about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In someembodiments (such as when the synthesis gas will be used as a feedstockto make methanol), such ratio may be about 3:1 (e.g., about 2.8:1 to3.2:1).

[0168] Certain embodiments may include blending a first synthesis gaswith a second synthesis gas to produce synthesis gas of a desiredcomposition. The first and the second synthesis gases may be producedfrom different portions of the formation.

[0169] Synthesis gases may be converted to heavier condensablehydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesisprocess may convert synthesis gas to branched and unbranched paraffins.Paraffins produced from the Fischer-Tropsch process may be used toproduce other products such as diesel, jet fuel, and naphtha products.The produced synthesis gas may also be used in a catalytic methanationprocess to produce methane. Alternatively, the produced synthesis gasmay be used for production of methanol, gasoline and diesel fuel,ammonia, and middle distillates. Produced synthesis gas may be used toheat the formation as a combustion fuel. Hydrogen in produced synthesisgas may be used to upgrade oil.

[0170] Synthesis gas may also be used for other purposes. Synthesis gasmay be combusted as fuel. Synthesis gas may also be used forsynthesizing a wide range of organic and/or inorganic compounds, such ashydrocarbons and ammonia. Synthesis gas may be used to generateelectricity by combusting it as a fuel, by reducing the pressure of thesynthesis gas in turbines, and/or using the temperature of the synthesisgas to make steam (and then run turbines). Synthesis gas may also beused in an energy generation unit such as a molten carbonate fuel cell,a solid oxide fuel cell, or other type of fuel cell.

[0171] Certain embodiments may include separating a fuel cell feedstream from fluids produced from pyrolysis of at least some of thehydrocarbons within a formation. The fuel cell feed stream may includeH₂, hydrocarbons, and/or carbon monoxide. In addition, certainembodiments may include directing the fuel cell feed stream to a fuelcell to produce electricity. The electricity generated from thesynthesis gas or the pyrolyzation fluids in the fuel cell may powerelectric heaters, which may heat at least a portion of the formation.Certain embodiments may include separating carbon dioxide from a fluidexiting the fuel cell. Carbon dioxide produced from a fuel cell or aformation may be used for a variety of purposes.

[0172] In certain embodiments, synthesis gas produced from a heatedformation may be transferred to an additional area of the formation andstored within the additional area of the formation for a length of time.The conditions of the additional area of the formation may inhibitreaction of the synthesis gas. The synthesis gas may be produced fromthe additional area of the formation at a later time.

[0173] In some embodiments, treating a formation may include injectingfluids into the formation. The method may include providing heat to theformation, allowing the heat to transfer to a selected section of theformation, injecting a fluid into the selected section, and producinganother fluid from the formation. Additional heat may be provided to atleast a portion of the formation, and the additional heat may be allowedto transfer from at least the portion to the selected section of theformation. At least some hydrocarbons may be pyrolyzed within theselected section and a mixture may be produced from the formation.Another embodiment may include leaving a section of the formationproximate the selected section substantially unleached. The unleachedsection may inhibit the flow of water into the selected section.

[0174] In an embodiment, heat may be provided to the formation. The heatmay be allowed to transfer to a selected section of the formation suchthat dissociation of carbonate minerals is inhibited. At least somehydrocarbons may be pyrolyzed within the selected section and a mixtureproduced from the formation. The method may further include reducing atemperature of the selected section and injecting a fluid into theselected section. Another fluid may be produced from the formation.Alternatively, subsequent to providing heat and allowing heat totransfer, a method may include injecting a fluid into the selectedsection and producing another fluid from the formation. Similarly, amethod may include injecting a fluid into the selected section andpyrolyzing at least some hydrocarbons within the selected section of theformation after providing heat and allowing heat to transfer to theselected section.

[0175] In an embodiment that includes injecting fluids, a method oftreating a formation may include providing heat from one or more heatsources and allowing the heat to transfer to a selected section of theformation such that a temperature of the selected section is less thanabout a temperature at which nahcolite dissociates. A fluid may beinjected into the selected section and another fluid may be producedfrom the formation. The method may further include providing additionalheat to the formation, allowing the additional heat to transfer to theselected section of the formation, and pyrolyzing at least somehydrocarbons within the selected section. A mixture may then be producedfrom the formation.

[0176] Certain embodiments that include injecting fluids may alsoinclude controlling the heating of the formation. A method may includeproviding heat to the formation, controlling the heat such that aselected section is at a first temperature, injecting a fluid into theselected section, and producing another fluid from the formation. Themethod may further include controlling the heat such that the selectedsection is at a second temperature that is greater than the firsttemperature. Heat may be allowed to transfer from the selected section,and at least some hydrocarbons may be pyrolyzed within the selectedsection of the formation. A mixture may be produced from the formation.

[0177] A further embodiment that includes injecting fluids may includeproviding heat to a formation, allowing the heat to transfer to aselected section of the formation, injecting a first fluid into theselected section, and producing a second fluid from the formation. Themethod may further include providing additional heat, allowing theadditional heat to transfer to the selected section of the formation,pyrolyzing at least some hydrocarbons within the selected section of theformation, and producing a mixture from the formation. In addition, atemperature of the selected section may be reduced and a third fluid maybe injected into the selected section. A fourth fluid may be producedfrom the formation.

[0178] In some embodiments, migration of fluids into and/or out of atreatment area may be inhibited. Inhibition of migration of fluids mayoccur before, during, and/or after an in situ treatment process. Forexample, migration of fluids may be inhibited while heat is providedfrom one or more heat sources to at least a portion of the treatmentarea. The heat may be allowed to transfer to at least a portion of thetreatment area. Fluids may be produced from the treatment area.

[0179] Barriers may be used to inhibit migration of fluids into and/orout of a treatment area in a formation. Barriers may include, but arenot limited to naturally occurring portions (e.g., overburden and/orunderburden), frozen barrier zones, low temperature barrier zones, groutwalls, sulfur wells, dewatering wells, and/or injection wells. Barriersmay define the treatment area. Alternatively, barriers may be providedto a portion of the treatment area.

[0180] In an embodiment, a method of treating a hydrocarbon containingformation in situ may include providing a refrigerant to a plurality ofbarrier wells to form a low temperature barrier zone. The method mayfurther include establishing a low temperature barrier zone. In someembodiments, the temperature within the low temperature barrier zone maybe lowered to inhibit the flow of water into or out of at least aportion of a treatment area in the formation.

[0181] Certain embodiments of treating a hydrocarbon containingformation in situ may include providing a refrigerant to a plurality ofbarrier wells to form a frozen barrier zone. The frozen barrier zone mayinhibit migration of fluids into and/or out of the treatment area. Incertain embodiments, a portion of the treatment area is below a watertable of the formation. In addition, the method may include controllingpressure to maintain a fluid pressure within the treatment area above ahydrostatic pressure of the formation and producing a mixture of fluidsfrom the formation.

[0182] Barriers may be provided to a portion of the formation prior to,during, and after providing heat from one or more heat sources to thetreatment area. For example, a barrier may be provided to a portion ofthe formation that has previously undergone a conversion process.

[0183] In some embodiments, migration of fluids into and/or out of atreatment area may be inhibited. Inhibition of migration of fluids mayoccur before, during, and/or after an in situ treatment process. Forexample, migration of fluids may be inhibited while heat is providedfrom heat sources to at least a portion of the treatment area. Barriersmay be used to inhibit migration of fluids into and/or out of atreatment area in a formation. Barriers may include, but are not limitedto naturally occurring portions and/or installed portions. In someembodiments, the barrier is a low temperature zone or frozen barrierformed by freeze wells installed around a perimeter of a treatment area.

[0184] Fluid may be introduced to a portion of the formation that haspreviously undergone an in situ conversion process. The fluid may beproduced from the formation in a mixture, which may contain additionalfluids present in the formation. In some embodiments, the producedmixture may be provided to an energy producing unit.

[0185] In some embodiments, one or more conditions in a selected sectionmay be controlled during an in situ conversion process to inhibitformation of carbon dioxide. Conditions may be controlled to producefluids having a carbon dioxide emission level that is less than aselected carbon dioxide level. For example, heat provided to theformation may be controlled to inhibit generation of carbon dioxide,while increasing production of molecular hydrogen.

[0186] In a similar manner, a method for producing methane from ahydrocarbon containing formation in situ while minimizing production ofCO₂ may include controlling the heat from the one or more heat sourcesto enhance production of methane in the produced mixture and generatingheat via at least one or more of the heat sources in a manner thatminimizes CO₂ production. The methane may further include controlling atemperature proximate the production wellbore at or above adecomposition temperature of ethane.

[0187] In certain embodiments, a method for producing products from aheated formation may include controlling a condition within a selectedsection of the formation to produce a mixture having a carbon dioxideemission level below a selected baseline carbon dioxide emission level.In some embodiments, the mixture may be blended with a fluid to generatea product having a carbon dioxide emission level below the baseline.

[0188] In an embodiment, a method for producing methane from a heatedformation in situ may include providing heat from one or more heatsources to at least one portion of the formation and allowing the heatto transfer to a selected section of the formation. The method mayfurther include providing hydrocarbon compounds to at least the selectedsection of the formation and producing a mixture including methane fromthe hydrocarbons in the formation.

[0189] One embodiment of a method for producing hydrocarbons in a heatedformation may include forming a temperature gradient in at least aportion of a selected section of the heated formation and providing ahydrocarbon mixture to at least the selected section of the formation. Amixture may then be produced from a production well.

[0190] In certain embodiments, a method for upgrading hydrocarbons in aheated formation may include providing hydrocarbons to a selectedsection of the heated formation and allowing the hydrocarbons to crackin the heated formation. The cracked hydrocarbons may be a higher gradethan the provided hydrocarbons. The upgraded hydrocarbons may beproduced from the formation.

[0191] Cooling a portion of the formation after an in situ conversionprocess may provide certain benefits, such as increasing the strength ofthe rock in the formation (thereby mitigating subsidence), increasingabsorptive capacity of the formation, etc.

[0192] In an embodiment, a portion of a formation that has beenpyrolyzed and/or subjected to synthesis gas generation may be allowed tocool or may be cooled to form a cooled, spent portion within theformation. For example, a heated portion of a formation may be allowedto cool by transference of heat to an adjacent portion of the formation.The transference of heat may occur naturally or may be forced by theintroduction of heat transfer fluids through the heated portion and intoa cooler portion of the formation.

[0193] In some embodiments, recovering thermal energy from a posttreatment hydrocarbon containing formation may include injecting a heatrecovery fluid into a portion of the formation. Heat from the formationmay transfer to the heat recovery fluid. The heat recovery fluid may beproduced from the formation. For example, introducing water to a portionof the formation may cool the portion. Water introduced into the portionmay be removed from the formation as steam. The removed steam or hotwater may be injected into a hot portion of the formation to createsynthesis gas

[0194] In an embodiment, hydrocarbons may be recovered from a posttreatment hydrocarbon containing formation by injecting a heat recoveryfluid into a portion of the formation. Heat may vaporize at least someof the heat recovery fluid and at least some hydrocarbons in theformation. A portion of the vaporized recovery fluid and the vaporizedhydrocarbons may be produced from the formation.

[0195] In certain embodiments, fluids in the formation may be removedfrom a post treatment hydrocarbon formation by injecting a heat recoveryfluid into a portion of the formation. Heat may transfer to the heatrecovery fluid and a portion of the fluid may be produced from theformation. The heat recovery fluid produced from the formation mayinclude at least some of the fluids in the formation.

[0196] In one embodiment, a method of recovering excess heat from aheated formation may include providing a product stream to the heatedformation, such that heat transfers from the heated formation to theproduct stream. The method may further include producing the productstream from the heated formation and directing the product stream to aprocessing unit. The heat of the product stream may then be transferredto the processing unit. In an alternative method for recovering excessheat from a heated formation, the heated product stream may be directedto another formation, such that heat transfers from the product streamto the other formation.

[0197] In one embodiment, a method of utilizing heat of a heatedformation may include placing a conduit in the formation, such thatconduit input may be located separately from conduit output. The conduitmay be heated by the heated formation to produce a region of reaction inat least a portion of the conduit. The method may further includedirecting a material through the conduit to the region of reaction. Thematerial may undergo change in the region of reaction. A product may beproduced from the conduit.

[0198] An embodiment of a method of utilizing heat of a heated formationmay include providing heat from one or more heat sources to at least oneportion of the formation and allowing the heat to transfer to a regionof reaction in the formation. Material may be directed to the region ofreaction and allowed to react in the region of reaction. A mixture maythen be produced from the formation.

[0199] In an embodiment, a portion of a hydrocarbon containing formationmay be used to store and/or sequester materials (e.g., formation fluids,carbon dioxide). The conditions within the portion of the formation mayinhibit reactions of the materials. Materials may be stored in theportion for a length of time. In addition, materials may be producedfrom the portion at a later time. Materials stored within the portionmay have been previously produced from the portion of the formation,and/or another portion of the formation.

[0200] In an embodiment, a portion of pyrolyzation fluids removed from aformation may be stored in an adjacent spent portion when treatmentfacilities that process removed pyrolyzation fluid are not able toprocess the portion. In certain embodiments, removal of pyrolyzationfluids stored in a spent formation may be facilitated by heating thespent formation.

[0201] In an embodiment, a portion of synthesis gas removed from aformation may be stored in an adjacent or nearby spent portion whentreatment facilities that process removed synthesis gas are not able toprocess the portion. In certain embodiments, removal of synthesis gasstored in a spent formation may be facilitated by heating the spentformation.

[0202] After an in situ conversion process has been completed in aportion of the formation, fluid may be sequestered within the formation.In some embodiments, to store a significant amount of fluid within theformation, a temperature of the formation will often need to be lessthan about 100° C. Water may be introduced into at least a portion ofthe formation to generate steam and reduce a temperature of theformation. The steam may be removed from the formation. The steam may beutilized for various purposes, including, but not limited to, heatinganother portion of the formation, generating synthesis gas in anadjacent portion of the formation, generating electricity, and/or as asteam flood in a oil reservoir. After the formation has cooled, fluid(e.g., carbon dioxide) may be pressurized and sequestered in theformation. Sequestering fluid within the formation may result in asignificant reduction or elimination of fluid that is released to theenvironment due to operation of the in situ conversion process.

[0203] In some embodiments, carbon dioxide may be injected underpressure into the portion of the formation. The injected carbon dioxidemay adsorb onto hydrocarbons in the formation and/or reside in voidspaces such as pores in the formation. The carbon dioxide may begenerated during pyrolysis, synthesis gas generation, and/or extractionof useful energy. In some embodiments, carbon dioxide may be stored inrelatively deep hydrocarbon containing formations and used to desorbmethane.

[0204] In one embodiment, a method for sequestering carbon dioxide in aheated formation may include precipitating carbonate compounds fromcarbon dioxide provided to a portion of the formation. In someembodiments, the portion may have previously undergone an in situconversion process. Carbon dioxide and a fluid may be provided to theportion of the formation. The fluid may combine with carbon dioxide inthe portion to precipitate carbonate compounds.

[0205] In some embodiments, methane may be recovered from a hydrocarboncontaining formation by providing heat to the formation. The heat maydesorb a substantial portion of the methane within the selected sectionof the formation. At least a portion of the methane may be produced fromthe formation.

[0206] In an embodiment, a method for purifying water in a spentformation may include providing water to the formation and filtering theprovided water in the formation. The filtered water may then be producedfrom the formation.

[0207] In an embodiment, treating a hydrocarbon containing formation insitu may include injecting a recovery fluid into the formation. Heat maybe provided from one or more heat sources to the formation. The heat maytransfer from one or more of the heat sources to a selected section ofthe formation and vaporize a substantial portion of recovery fluid in atleast a portion of the selected section. The heat from the heat sourcesand the vaporized recovery fluid may pyrolyze at least some hydrocarbonswithin the selected section. A gas mixture may be produced from theformation. The produced gas mixture may include hydrocarbons with anaverage API gravity greater than about 25°.

[0208] In certain embodiments, a method of shutting-in an in situtreatment process in a hydrocarbon containing formation may includeterminating heating from one or more heat sources providing heat to aportion of the formation. A pressure may be monitored and controlled inat least a portion of the formation. The pressure may be maintainedapproximately below a fracturing or breakthrough pressure of theformation.

[0209] One embodiment of a method of shutting-in an in situ treatmentprocess in a hydrocarbon containing formation may include terminatingheating from one or more heat sources providing heat to a portion of theformation. Hydrocarbon vapor may be produced from the formation. Atleast a portion of the produced hydrocarbon vapor may be injected into aportion of a storage formation. The hydrocarbon vapor may be injectedinto a relatively high temperature formation. A substantial portion ofinjected hydrocarbons may be converted to coke and H₂ in the relativelyhigh temperature formation. Alternatively, the hydrocarbon vapor may bestored in a depleted formation.

[0210] In an embodiment, one or more openings (or wellbores) may beformed in a hydrocarbon containing formation. A first opening may beformed in the formation. A plurality of magnets may be provided to thefirst opening. The plurality of magnets may be positioned along aportion of the first opening. The plurality of magnets may produce aseries of magnetic fields along the portion of the first opening.

[0211] A second opening may be formed in the formation using magnetictracking of the series of magnetic fields produced by the plurality ofmagnets in the first opening. Magnetic tracking may be used to form thesecond opening an approximate desired distance from the first opening.In certain embodiments, the deviation in spacing between the firstopening and the second opening may be less than or equal to about ±0.5m.

[0212] In some embodiments, the plurality of magnets may form a magneticstring. The magnetic string may include one or more magnetic segments.In certain embodiments, each magnetic segment may include a plurality ofmagnets. The magnetic segments may include an effective north pole andan effective south pole. In an embodiment, two adjacent magneticsegments are positioned with opposing poles to form a junction ofopposing poles.

[0213] In some embodiments, a current may be passed into a casing of awell. The current in the casing may generate a magnetic field. Themagnetic field may be detected and utilized to guide drilling of anadjacent well or wells. A portion of the casing may be insulated toinhibit current loss to the formation. In some embodiments, an insulatedwire may be positioned in a well. A current passed through the insulatedwire may generate a magnetic field. The magnetic field may be detectedand utilized to guide drilling of an adjacent well or wells.

[0214] In some embodiments, acoustics may be used to guide placement ofa well in a formation. For example, reflections of a noise signalgenerated from a noise source in a well being drilled may be used todetermine an approximate position of the drill bit relative to ageological discontinuity in the formation.

[0215] Multiple openings may be formed in a hydrocarbon containingformation. In an embodiment, the multiple openings may form a pattern ofopenings. A first opening may be formed in the formation. A magneticstring may be placed in the first opening to produce magnetic fields ina portion of the formation. A first set of openings may be formed usingmagnetic tracking of the magnetic string. The magnetic string may bemoved to a first opening in the first set of openings. A second set ofopenings may be formed using magnetic tracking of the magnetic stringlocated in the first opening in the first set of openings. In oneembodiment, a third set of openings may be formed by using magnetictracking of the magnetic string, where the magnetic string is located inan opening in the second set of openings. In another embodiment, a thirdset of openings may be formed by using magnetic tracking of the magneticstring, where the magnetic string is located in another opening in the,first set of openings.

[0216] A system for forming openings in a hydrocarbon containingformation may include a drilling apparatus, a magnetic string, and asensor. The magnetic string may include two or more magnetic segmentspositioned within a conduit. Each of the magnetic segments may include aplurality of magnets. The sensor may be used to detect magnetic fieldswithin the formation produced by the magnetic string. The magneticstring may be placed in a first opening and the drilling apparatus andsensor in a second opening.

[0217] One or more heaters may be disposed within an opening in ahydrocarbon containing formation such that the heaters transfer heat tothe formation. In some embodiments, a heater may be placed in an openwellbore in the formation. An “open wellbore” in a formation may be awellbore without casing or an “uncased wellbore.” Heat may conductivelyand radiatively transfer from the heater to the formation.Alternatively, a heater may be placed within a heater well that may bepacked with gravel, sand, and/or cement or a heater well with a casing.

[0218] In an embodiment, a conductor-in-conduit heater having a desiredlength may be assembled. A conductor may be placed within a conduit toform the conductor-in-conduit heater. Two or more conductor-in-conduitheaters may be coupled together to form a heater having the desiredlength. The conductors of the conductor-in-conduit heaters may beelectrically coupled together. In addition, the conduits may beelectrically coupled together. A desired length of theconductor-in-conduit may be placed in an opening in the hydrocarboncontaining formation. In some embodiments, individual sections of theconductor-in-conduit heater may be coupled using shielded active gaswelding.

[0219] In certain embodiments, a heater of a desired length may beassembled proximate the hydrocarbon containing formation. The assembledheater may then be coiled. The heater may be placed in the hydrocarboncontaining formation by uncoiling the heater into the opening in thehydrocarbon containing formation.

[0220] In an embodiment, a system and a method may include an opening inthe formation extending from a first location on the surface of theearth to a second location on the surface of the earth. Heat sources maybe placed within the opening to provide heat to at least a portion ofthe formation.

[0221] A conduit may be positioned in the opening extending from thefirst location to the second location. In an embodiment, a heat sourcemay be positioned proximate and/or in the conduit to provide heat to theconduit. Transfer of the heat through the conduit may provide heat to apart of the formation. In some embodiments, an additional heater may beplaced in an additional conduit to provide heat to the part of theformation through the additional conduit.

[0222] In some embodiments, an annulus is formed between a wall of theopening and a wall of the conduit placed within the opening extendingfrom the first location to the second location. A heat source may beplace proximate and/or in the annulus to provide heat to a portion theopening. The provided heat may transfer through the annulus to a part ofthe formation.

[0223] A method for controlling an in situ system of treating ahydrocarbon containing formation may include monitoring at least oneacoustic event within the formation using at least one acoustic detectorplaced within a wellbore in the formation. At least one acoustic eventmay be recorded with an acoustic monitoring system. In an embodiment, anacoustic source may be used to generate at least one acoustic event. Themethod may also include analyzing the at least one acoustic event todetermine at least one property of the formation. The in situ system maybe controlled based on the analysis of the at least one acoustic event.

[0224] In some embodiments, subjecting hydrocarbons to an in situconversion process may mature portions of the hydrocarbons. For example,application of heat to a coal formation may alter properties of coal inthe formation. In some embodiments, portions of the coal formation maybe converted to a higher rank of coal. Application of heat may reducewater content and/or volatile compound content of coal in the coalformation. Formation fluids (e.g., water and/or volatile compounds) maybe removed in a vapor phase. In other embodiments, formation fluids maybe removed in liquid and vapor phases or in a liquid phase. Temperatureand pressure in at least a portion of the formation may be controlledduring pyrolysis to yield improved products from the formation. Afterapplication of heat, coal may be produced from the formation. The coalmay be anthracitic.

[0225] In some embodiments, a recovery fluid may be used to remediatehydrocarbon containing formation treated by in situ conversion process.In some embodiments, hydrocarbons may be recovered from a hydrocarboncontaining formation before, during, and/or after treatment by injectinga recovery fluid into a portion of the formation. The recovery fluid maycause fluids within the formation to be produced. In some embodiments,the formation fluids may be separated from the recovery fluid at thesurface.

[0226] In some in situ conversion process embodiments, non-hydrocarbonmaterials such as minerals, metals, and other economically viablematerials contained within the formation may be economically producedfrom the formation. In certain embodiments, non-hydrocarbon materialsmay be recovered and/or produced prior to, during, and/or after the insitu conversion process for treating hydrocarbons using an additional insitu process of treating the formation for producing the non-hydrocarbonmaterials.

[0227] In an embodiment, hydrocarbons within a kerogen and liquidhydrocarbon containing formation may be converted in situ within theformation to yield a mixture of relatively high quality hydrocarbonproducts, hydrogen, and/or other products. One or more heaters may beused to heat a portion of the kerogen and liquid hydrocarbon containingformation to temperatures that allow pyrolysis of the hydrocarbons. Inan embodiment, a portion of the kerogen in the portion may be pyrolyzed.In certain embodiments, at least a portion of the liquid hydrocarbons inthe portion of the formation may be mobilized (e.g., the liquidhydrocarbons may be mobilized after kerogen in the formation ispyrolyzed). Hydrocarbons, hydrogen, and other formation fluids may beremoved from the formation through one or more production wells. In someembodiments, formation fluids may be removed in a vapor phase. In otherembodiments, formation fluids may be removed in liquid and vapor phasesor in a liquid phase. Temperature and pressure in at least a portion ofthe formation may be controlled during pyrolysis to yield improvedproducts from the formation.

[0228] In some embodiments, electrical heaters in a formation may betemperature limited heaters. The use of temperature limited heaters mayeliminate the need for temperature controllers to regulate energy inputinto the formation from the heaters. In some embodiments, thetemperature limited heaters may be Curie temperature heaters. Heatdissipation from portions of a Curie temperature heater may adjust tolocal conditions so that energy input to the entire heater does not needto be adjusted (i.e., reduced) to compensate for localized hot spotsadjacent to the heater. In some embodiments, temperature limited heatersmay be used to efficiently heat formations that have low thermalconductivity layers.

[0229] In some heat source embodiments and freeze well embodiments,wells in the formation may have two entries into the formation at thesurface. In some embodiments, wells with two entries into the formationare formed using river crossing rigs to drill the wells.

[0230] In some embodiments, heating of regions in a volume may bestarted at selected times. Starting heating of regions in the volume atselected times may allow for accommodation of geomechanical motion thatwill occur as the formation is heated.

BRIEF DESCRIPTION OF THE DRAWINGS

[0231] Advantages of the present invention may become apparent to thoseskilled in the art with the benefit of the following detaileddescription of the preferred embodiments and upon reference to theaccompanying drawings in which:

[0232]FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation.

[0233]FIG. 2 depicts a diagram that presents several properties ofkerogen resources.

[0234]FIG. 3 shows a schematic view of an embodiment of a portion of anin situ conversion system for treating a hydrocarbon containingformation.

[0235]FIG. 4 depicts an embodiment of a heater well.

[0236]FIG. 5 depicts an embodiment of a heater well.

[0237]FIG. 6 depicts an embodiment of a heater well.

[0238]FIG. 7 illustrates a schematic view of multiple heaters branchedfrom a single well in a hydrocarbon containing formation.

[0239]FIG. 8 illustrates a schematic of an elevated view of multipleheaters branched from a single well in a hydrocarbon containingformation.

[0240]FIG. 9 depicts an embodiment of heater wells located in ahydrocarbon containing formation.

[0241]FIG. 10 depicts an embodiment of a pattern of heater wells in ahydrocarbon containing formation.

[0242]FIG. 11 depicts an embodiment of a heated portion of a hydrocarboncontaining formation.

[0243]FIG. 12 depicts an embodiment of superposition of heat in ahydrocarbon containing formation.

[0244]FIG. 13 illustrates an embodiment of a production well placed in aformation.

[0245]FIG. 14 depicts an embodiment of a pattern of heat sources andproduction wells in a hydrocarbon containing formation.

[0246]FIG. 15 depicts an embodiment of a pattern of heat sources and aproduction well in a hydrocarbon containing formation.

[0247]FIG. 16 illustrates a computational system.

[0248]FIG. 17 depicts a block diagram of a computational system.

[0249]FIG. 18 illustrates a flow chart of an embodiment of acomputer-implemented method for treating a formation based on acharacteristic of the formation.

[0250]FIG. 19 illustrates a schematic of an embodiment used to controlan in situ conversion process in a formation.

[0251]FIG. 20 illustrates a flow chart of an embodiment of a method formodeling an in situ process for treating a hydrocarbon containingformation using a computer system.

[0252]FIG. 21 illustrates a plot of a porosity-permeabilityrelationship.

[0253]FIG. 22 illustrates a method for simulating heat transfer in aformation.

[0254]FIG. 23 illustrates a model for simulating a heat transfer rate ina formation.

[0255]FIG. 24 illustrates a flow chart of an embodiment of a method forusing a computer system to model an in situ conversion process.

[0256]FIG. 25 illustrates a flow chart of an embodiment of a method forcalibrating model parameters to match laboratory or field data for an insitu process.

[0257]FIG. 26 illustrates a flow chart of an embodiment of a method forcalibrating model parameters.

[0258]FIG. 27 illustrates a flow chart of an embodiment of a method forcalibrating model parameters for a second simulation method using asimulation method.

[0259]FIG. 28 illustrates a flow chart of an embodiment of a method fordesign and/or control of an in situ process.

[0260]FIG. 29 depicts a method of modeling one or more stages of atreatment process.

[0261]FIG. 30 illustrates a flow chart of an embodiment of a method fordesigning and controlling an in situ process with a simulation method ona computer system.

[0262]FIG. 31 illustrates a model of a formation that may be used insimulations of deformation characteristics according to one embodiment.

[0263]FIG. 32 illustrates a schematic of a strip development accordingto one embodiment.

[0264]FIG. 33 depicts a schematic illustration of a treated portion thatmay be modeled with a simulation.

[0265]FIG. 34 depicts a horizontal cross section of a model of aformation for use by a simulation method according to one embodiment.

[0266]FIG. 35 illustrates a flow chart of an embodiment of a method formodeling deformation due to in situ treatment of a hydrocarboncontaining formation.

[0267]FIG. 36 depicts a profile of richness versus depth in a model ofan oil shale formation.

[0268]FIG. 37 illustrates a flow chart of an embodiment of a method forusing a computer system to design and control an in situ conversionprocess.

[0269]FIG. 38 illustrates a flow chart of an embodiment of a method fordetermining operating conditions to obtain desired deformationcharacteristics.

[0270]FIG. 39 illustrates the influence of operating pressure onsubsidence in a cylindrical model of a formation from a finite elementsimulation.

[0271]FIG. 40 illustrates the influence of an untreated portion betweentwo treated portions.

[0272]FIG. 41 illustrates the influence of an untreated portion betweentwo treated portions.

[0273]FIG. 42 represents shear deformation of a formation at thelocation of selected heat sources as a function of depth.

[0274]FIG. 43 illustrates a method for controlling an in situ processusing a computer system.

[0275]FIG. 44 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a computer simulation method.

[0276]FIG. 45 illustrates several ways that information may betransmitted from an in situ process to a remote computer system.

[0277]FIG. 46 illustrates a schematic of an embodiment for controllingan in situ process in a formation using information.

[0278]FIG. 47 illustrates a schematic of an embodiment for controllingan in situ process in a formation using a simulation method and acomputer system.

[0279]FIG. 48 illustrates a flow chart of an embodiment of acomputer-implemented method for determining a selected overburdenthickness.

[0280]FIG. 49 illustrates a schematic diagram of a plan view of a zonebeing treated using an in situ conversion process.

[0281]FIG. 50 illustrates a schematic diagram of a cross-sectionalrepresentation of a zone being treated using an in situ conversionprocess.

[0282]FIG. 51 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation.

[0283]FIG. 52 depicts an embodiment of a natural distributed combustorheat source.

[0284]FIG. 53 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0285]FIG. 54 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit.

[0286]FIG. 55 depicts a schematic representation of an embodiment of aheater well positioned within a hydrocarbon containing formation.

[0287]FIG. 56 depicts a portion of an overburden of a formation with anatural distributed combustor heat source.

[0288]FIG. 57 depicts an embodiment of a natural distributed combustorheat source.

[0289]FIG. 58 depicts an embodiment of a natural distributed combustorheat source.

[0290]FIG. 59 depicts an embodiment of a natural distributed combustorsystem for heating a formation.

[0291]FIG. 60 depicts an embodiment of an insulated conductor heatsource.

[0292]FIG. 61 depicts an embodiment of an insulated conductor heatsource.

[0293]FIG. 62 depicts an embodiment of a transition section of aninsulated conductor assembly.

[0294]FIG. 63 depicts an embodiment of an insulated conductor heatsource.

[0295]FIG. 64 depicts an embodiment of a wellhead of an insulatedconductor heat source.

[0296]FIG. 65 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0297]FIG. 66 depicts an embodiment of three insulated conductor heatersplaced within a conduit.

[0298]FIG. 67 depicts an embodiment of a centralizer.

[0299]FIG. 68 depicts an embodiment of a centralizer.

[0300]FIG. 69 depicts an embodiment of a centralizer.

[0301]FIG. 70 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source.

[0302]FIG. 71 depicts an embodiment of a sliding connector.

[0303]FIG. 72 depicts an embodiment of a wellhead with aconductor-in-conduit heat source.

[0304]FIG. 73 illustrates a schematic of an embodiment of aconductor-in-conduit heater, where a portion of the heater is placedsubstantially horizontally within a formation.

[0305]FIG. 74 illustrates an enlarged view of an embodiment of ajunction of a conductor-in-conduit heater.

[0306]FIG. 75 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0307]FIG. 76 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0308]FIG. 77 illustrates a schematic of an embodiment of aconductor-in-conduit heater, wherein a portion of the heater is placedsubstantially horizontally within a formation.

[0309]FIG. 78 depicts a cross-sectional view of a portion of anembodiment of a cladding section coupled to a heater support and aconduit.

[0310]FIG. 79 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor.

[0311]FIG. 80 depicts a portion of an embodiment of aconductor-in-conduit heat source with a cutout view showing acentralizer on the conductor.

[0312]FIG. 81 depicts a cross-sectional representation of an embodimentof a centralizer.

[0313]FIG. 82 depicts a cross-sectional representation of an embodimentof a centralizer.

[0314]FIG. 83 depicts a top view of an embodiment of a centralizer.

[0315]FIG. 84 depicts a top view of an embodiment of a centralizer.

[0316]FIG. 85 depicts a cross-sectional representation of a portion ofan embodiment of a section of a conduit of a conductor-in-conduit heatsource with an insulation layer wrapped around the conductor.

[0317]FIG. 86 depicts a cross-sectional representation of an embodimentof a cladding section coupled to a low resistance conductor.

[0318]FIG. 87 depicts an embodiment of a conductor-in-conduit heatsource in a formation.

[0319]FIG. 88 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation.

[0320]FIG. 89 depicts an embodiment of a conductor-in-conduit heatsource to be installed in a formation.

[0321]FIG. 90 shows a cross-sectional representation of an end of atubular around which two pairs of diametrically opposite electrodes arearranged.

[0322]FIG. 91 depicts an embodiment of ends of two adjacent tubularsbefore forge welding.

[0323]FIG. 92 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes.

[0324]FIG. 93 illustrates a cross-sectional representation of anembodiment of two conductor-in-conduit heat source sections before forgewelding.

[0325]FIG. 94 depicts an embodiment of heat sources installed in aformation.

[0326]FIG. 95 depicts an embodiment of a heat source in a formation.

[0327]FIG. 96 depicts an embodiment of a heat source in a formation.

[0328]FIG. 97 illustrates a cross-sectional representation of anembodiment of a heater with two oxidizers.

[0329]FIG. 98 illustrates a cross-sectional representation of anembodiment of a heater with an oxidizer and an electric heater.

[0330]FIG. 99 depicts a cross-sectional representation of an embodimentof a heater with an oxidizer and a flameless distributed combustorheater.

[0331]FIG. 100 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater.

[0332]FIG. 101 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater with two conduits.

[0333]FIG. 102 illustrates a cross-sectional representation of anembodiment of a downhole combustor.

[0334]FIG. 102A depicts an embodiment of a heat source for a hydrocarboncontaining formation.

[0335]FIG. 103 depicts a representation of a portion of a piping layoutfor heating a formation using downhole combustors.

[0336]FIG. 104 depicts a schematic representation of an embodiment of aheater well positioned within a hydrocarbon containing formation.

[0337]FIG. 105 depicts an embodiment of a heat source positioned in ahydrocarbon containing formation.

[0338]FIG. 106 depicts a schematic representation of an embodiment of aheat source positioned in a hydrocarbon containing formation.

[0339]FIG. 107 depicts an embodiment of a surface combustor heat source.

[0340]FIG. 108. depicts an embodiment of a conduit for a heat sourcewith a portion of an inner conduit shown cut away to show a center tube.

[0341]FIG. 109 depicts an embodiment of a flameless combustor heatsource.

[0342]FIG. 110 illustrates a representation of an embodiment of anexpansion mechanism coupled to a heat source in an opening in aformation.

[0343]FIG. 111 illustrates a schematic of a thermocouple placed in awellbore.

[0344]FIG. 112 depicts a schematic of a well embodiment for usingpressure waves to measure temperature within a wellbore.

[0345]FIG. 113 illustrates a schematic of an embodiment that uses windto generate electricity to heat a formation.

[0346]FIG. 114 depicts an embodiment of a windmill for generatingelectricity.

[0347]FIG. 115 illustrates a schematic of an embodiment for using solarpower to heat a formation.

[0348]FIG. 116 depicts a cross-sectional representation of an embodimentfor treating a lean zone and a rich zone of a formation.

[0349]FIG. 117 depicts an embodiment of using pyrolysis water togenerate synthesis-gas in a formation.

[0350]FIG. 118 depicts an embodiment of synthesis gas production in aformation.

[0351]FIG. 119 depicts an embodiment of continuous synthesis gasproduction in a formation.

[0352]FIG. 120 depicts an embodiment of batch synthesis gas productionin a formation.

[0353]FIG. 121 depicts an embodiment of producing energy with synthesisgas produced from a hydrocarbon containing formation.

[0354]FIG. 122 depicts an embodiment of producing energy withpyrolyzation fluid produced from a hydrocarbon containing formation.

[0355]FIG. 123 depicts an embodiment of synthesis gas production from aformation.

[0356]FIG. 124 depicts an embodiment of sequestration of carbon dioxideproduced during pyrolysis in a hydrocarbon containing formation.

[0357]FIG. 125 depicts an embodiment of producing energy with synthesisgas produced from a hydrocarbon containing formation.

[0358]FIG. 126 depicts an embodiment of a Fischer-Tropsch process usingsynthesis gas produced from a hydrocarbon containing formation.

[0359]FIG. 127 depicts an embodiment of a Shell Middle Distillatesprocess using synthesis gas produced from a hydrocarbon containingformation.

[0360]FIG. 128 depicts an embodiment of a catalytic methanation processusing synthesis gas produced from a hydrocarbon containing formation.

[0361]FIG. 129 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from a hydrocarbon containing formation.

[0362]FIG. 130 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from a hydrocarbon containing formation.

[0363]FIG. 131 depicts an embodiment of preparation of a feed stream foran ammonia and urea process.

[0364]FIG. 132 depicts an embodiment for treating a relatively permeableformation.

[0365]FIG. 133 depicts an embodiment for treating a relatively permeableformation.

[0366]FIG. 134 depicts an embodiment of heat sources in a relativelypermeable formation.

[0367]FIG. 135 depicts an embodiment of heat sources in a relativelypermeable formation.

[0368]FIG. 136 depicts an embodiment for treating a relatively permeableformation.

[0369]FIG. 137 depicts an embodiment for treating a relatively permeableformation.

[0370]FIG. 138 depicts an embodiment for treating a relatively permeableformation.

[0371]FIG. 139 depicts an embodiment of a heater well with selectiveheating.

[0372]FIG. 140 depicts a cross-sectional representation of an embodimentfor treating a formation with multiple heating sections.

[0373]FIG. 141 depicts an end view schematic of an embodiment fortreating a relatively permeable formation using a combination ofproducer and heater wells in the formation.

[0374]FIG. 142 depicts a side view schematic of the embodiment depictedin FIG. 141.

[0375]FIG. 143 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0376]FIG. 144 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0377]FIG. 145A depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0378]FIG. 145B depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0379]FIG. 146 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation.

[0380]FIG. 147 depicts a cross-sectional representation of an embodimentfor treating a relatively permeable formation.

[0381]FIG. 148 depicts a cross-sectional representation of an embodimentof production well placed in a formation.

[0382]FIG. 149 depicts linear relationships between total mass recoveryversus API gravity for three different tar sand formations.

[0383]FIG. 150 depicts schematic of an embodiment of a relativelypermeable formation used to produce a first mixture that is blended witha second mixture.

[0384]FIG. 151 depicts asphaltene content (on a whole oil basis) in ablend versus percent blending agent.

[0385]FIG. 152 depicts SARA results (saturate/aromatic ratio versusasphaltene/resin ratio) for several blends.

[0386]FIG. 153 illustrates near infrared transmittance versus volume ofn-heptane added to a first mixture.

[0387]FIG. 154 illustrates near infrared transmittance versus volume ofn-heptane added to a second mixture.

[0388]FIG. 155 illustrates near infrared transmittance versus volume ofn-heptane added to a third mixture.

[0389]FIG. 156 depicts changes in density with increasing temperaturefor several mixtures.

[0390]FIG. 157 depicts changes in viscosity with increasing temperaturefor several mixtures.

[0391]FIG. 158 depicts an embodiment of heat sources and productionwells in a relatively low permeability formation.

[0392]FIG. 159 depicts an embodiment of heat sources in a relatively lowpermeability formation.

[0393]FIG. 160 depicts an embodiment of heat sources in a relatively lowpermeability formation.

[0394]FIG. 161 depicts an embodiment of heat sources in a relatively lowpermeability formation.

[0395]FIG. 162 depicts an embodiment of heat sources in a relatively lowpermeability formation.

[0396]FIG. 163 depicts an embodiment of heat sources in a relatively lowpermeability formation.

[0397]FIG. 164 depicts an embodiment of a heat source and productionwell pattern.

[0398]FIG. 165 depicts an embodiment of a heat source and productionwell pattern.

[0399]FIG. 166 depicts an embodiment of a heat source and productionwell pattern.

[0400]FIG. 167 depicts an embodiment of a heat source and productionwell pattern.

[0401]FIG. 168 depicts an embodiment of a heat source and productionwell pattern.

[0402]FIG. 169 depicts an embodiment of a heat source and productionwell pattern.

[0403]FIG. 170 depicts an embodiment of a heat source and productionwell pattern.

[0404]FIG. 171 depicts an embodiment of a heat source and productionwell pattern.

[0405]FIG. 172 depicts an embodiment of a heat source and productionwell pattern.

[0406]FIG. 173 depicts an embodiment of a heat source and productionwell pattern.

[0407]FIG. 174 depicts an embodiment of a heat source and productionwell pattern.

[0408]FIG. 175 depicts an embodiment of a heat source and productionwell pattern.

[0409]FIG. 176 depicts an embodiment of a heat source and productionwell pattern.

[0410]FIG. 177 depicts an embodiment of a heat source and productionwell pattern.

[0411]FIG. 178 depicts an embodiment of a square pattern of heat sourcesand production wells.

[0412]FIG. 179 depicts an embodiment of a heat source and productionwell pattern.

[0413]FIG. 180 depicts an embodiment of a triangular pattern of heatsources.

[0414]FIG. 181 depicts an embodiment of a square pattern of heatsources.

[0415]FIG. 182 depicts an embodiment of a hexagonal pattern of heatsources.

[0416]FIG. 183 depicts an embodiment of a 12 to 1 pattern of heatsources.

[0417]FIG. 184 depicts an embodiment of treatment facilities fortreating a formation fluid.

[0418]FIG. 185 depicts an embodiment of a catalytic flamelessdistributed combustor.

[0419]FIG. 186 depicts an embodiment of treatment facilities fortreating a formation fluid.

[0420]FIG. 187 depicts a temperature profile for a triangular pattern ofheat sources.

[0421]FIG. 188 depicts a temperature profile for a square pattern ofheat sources.

[0422]FIG. 189 depicts a temperature profile for a hexagonal pattern ofheat sources.

[0423]FIG. 190 depicts a comparison plot between the average patterntemperature and temperatures at the coldest spots for various patternsof heat sources.

[0424]FIG. 191 depicts a comparison plot between the average patterntemperature and temperatures at various spots within triangular andhexagonal patterns of heat sources.

[0425]FIG. 192 depicts a comparison plot between the average patterntemperature and temperatures at various spots within a square pattern ofheat sources.

[0426]FIG. 193 depicts a comparison plot between temperatures at thecoldest spots of various patterns of heat sources.

[0427]FIG. 194 depicts in situ temperature profiles for electricalresistance heaters and natural distributed combustion heaters.

[0428]FIG. 195 depicts extension of a reaction zone in a heatedformation over time.

[0429]FIG. 196 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0430]FIG. 197 depicts the ratio of conductive heat transfer toradiative heat transfer in a formation.

[0431]FIG. 198 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0432]FIG. 199 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0433]FIG. 200 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0434]FIG. 201 depicts temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation.

[0435]FIG. 202 depicts a retort and collection system.

[0436]FIG. 203 depicts percentage of hydrocarbon fluid having carbonnumbers greater than 25 as a function of pressure and temperature foroil produced from an oil shale formation.

[0437]FIG. 204 depicts quality of oil as a function of pressure andtemperature for oil produced from an oil shale formation.

[0438]FIG. 205 depicts ethene to ethane ratio produced from an oil shaleformation as a function of temperature and pressure.

[0439]FIG. 206 depicts yield of fluids produced from an oil shaleformation as a function of temperature and pressure.

[0440]FIG. 207 depicts a plot of oil yield produced from treating an oilshale formation.

[0441]FIG. 208 depicts yield of oil produced from treating an oil shaleformation.

[0442]FIG. 209 depicts hydrogen to carbon ratio of hydrocarboncondensate produced from an oil shale formation as a function oftemperature and pressure.

[0443]FIG. 210 depicts olefin to paraffin ratio of hydrocarboncondensate produced from an oil shale formation as a function ofpressure and temperature.

[0444]FIG. 211 depicts relationships between properties of a hydrocarbonfluid produced from an oil shale formation as a function of hydrogenpartial pressure.

[0445]FIG. 212 depicts quantity of oil produced from an oil shaleformation as a function of partial pressure of H₂.

[0446]FIG. 213 depicts ethene to ethane ratios of fluid produced from anoil shale formation as a function of temperature and pressure.

[0447]FIG. 214 depicts hydrogen to carbon atomic ratios of fluidproduced from an oil shale formation as a function of temperature andpressure.

[0448]FIG. 215 depicts a heat source and production well pattern for afield experiment in an oil shale formation.

[0449]FIG. 216 depicts a cross-sectional representation of the fieldexperiment.

[0450]FIG. 217 depicts a plot of temperature within the oil shaleformation during the field experiment.

[0451]FIG. 218 depicts a plot of hydrocarbon liquids production overtime for the in situ field experiment.

[0452]FIG. 219 depicts a plot of production of hydrocarbon liquids, gas,and water for the in situ field experiment.

[0453]FIG. 220 depicts pressure within the oil shale formation duringthe field experiment.

[0454]FIG. 221 depicts a plot of API gravity of a fluid produced fromthe oil shale formation during the field experiment versus time.

[0455]FIG. 222 depicts average carbon numbers of fluid produced from theoil shale formation during the field experiment versus time.

[0456]FIG. 223 depicts density of fluid produced from the oil shaleformation during the field experiment versus time.

[0457]FIG. 224 depicts a plot of weight percent of hydrocarbons withinfluid produced from the oil shale formation during the field experiment.

[0458]FIG. 225 depicts a plot of weight percent versus carbon number ofproduced oil from the oil shale formation during the field experiment.

[0459]FIG. 226 depicts oil recovery versus heating rate for experimentaland laboratory oil shale data.

[0460]FIG. 227 depicts total hydrocarbon production and liquid phasefraction versus time of a fluid produced from an oil shale formation.

[0461]FIG. 228 depicts weight percent of paraffins versus vitrinitereflectance.

[0462]FIG. 229 depicts weight percent of cycloalkanes in produced oilversus vitrinite reflectance.

[0463]FIG. 230 depicts weight percentages of paraffins and cycloalkanesin produced oil versus vitrinite reflectance.

[0464]FIG. 231 depicts phenol weight percent in produced oil versusvitrinite reflectance.

[0465]FIG. 232 depicts aromatic weight percent in produced oil versusvitrinite reflectance.

[0466]FIG. 233 depicts ratios of paraffins to aromatics and aliphaticsto aromatics versus vitrinite reflectance.

[0467]FIG. 234 depicts the compositions of condensable hydrocarbonsproduced when various ranks of coal were treated.

[0468]FIG. 235 depicts yields of paraffins versus vitrinite reflectance.

[0469]FIG. 236 depicts yields of cycloalkanes versus vitrinitereflectance.

[0470]FIG. 237 depicts yields of cycloalkanes and paraffins versusvitrinite reflectance.

[0471]FIG. 238 depicts yields of phenols versus vitrinite reflectance.

[0472]FIG. 239 depicts API gravity as a function of vitrinitereflectance.

[0473]FIG. 240 depicts yield of oil from a coal formation as a functionof vitrinite reflectance.

[0474]FIG. 241 depicts CO₂ yield from coal having various vitrinitereflectances.

[0475]FIG. 242 depicts CO₂ yield versus atomic O/C ratio for a coalformation.

[0476]FIG. 243 depicts a schematic of a coal cube experiment.

[0477]FIG. 244 depicts an embodiment of an apparatus for a drumexperiment.

[0478]FIG. 245 depicts equilibrium gas phase compositions produced fromexperiments on a coal cube and a coal drum.

[0479]FIG. 246 depicts cumulative condensable hydrocarbons as a functionof temperature produced by heating a coal in a cube and coal in a drum.

[0480]FIG. 247 depicts cumulative production of gas as a function oftemperature produced by heating a coal in a cube and coal in a drum.

[0481]FIG. 248 depicts thermal conductivity of coal versus temperature.

[0482]FIG. 249 depicts locations of heat sources and wells in anexperimental field test.

[0483]FIG. 250 depicts a cross-sectional representation of the in situexperimental field test.

[0484]FIG. 251 depicts temperature versus time in the experimental fieldtest.

[0485]FIG. 252 depicts temperature versus time in the experimental fieldtest.

[0486]FIG. 253 depicts volume of oil produced from the experimentalfield test as a function of time.

[0487]FIG. 254 depicts volume of gas produced from a coal formation inthe experimental field test as a function of time.

[0488]FIG. 255 depicts carbon number distribution of fluids producedfrom the experimental field test.

[0489]FIG. 256 depicts weight percentages of various fluids producedfrom a coal formation for various heating rates in laboratoryexperiments.

[0490]FIG. 257 depicts weight percent of a hydrocarbon produced from twolaboratory experiments on coal from the field test site versus carbonnumber distribution.

[0491]FIG. 258 depicts fractions from separation of coal oils treated byFischer Assay and treated by slow heating in a coal cube experiment.

[0492]FIG. 259 depicts percentage ethene to ethane produced from a coalformation as a function of heating rate in laboratory experiments.

[0493]FIG. 260 depicts a plot of ethene to ethane ratio versus hydrogenconcentration.

[0494]FIG. 261 depicts product quality of fluids produced from a coalformation as a function of heating rate in laboratory experiments.

[0495]FIG. 262 depicts CO₂ produced at three different locations versustime in the experimental field test.

[0496]FIG. 263 depicts volatiles produced from a coal formation in theexperimental field test versus cumulative energy content.

[0497]FIG. 264 depicts volume of oil produced from a coal formation inthe experimental field test as a function of energy input.

[0498]FIG. 265 depicts synthesis gas production from the coal formationin the experimental field test versus the total water inflow.

[0499]FIG. 266 depicts additional synthesis gas production from the coalformation in the experimental field test due to injected steam.

[0500]FIG. 267 depicts the effect of methane injection into a heatedformation.

[0501]FIG. 268 depicts the effect of ethane injection into a heatedformation.

[0502]FIG. 269 depicts the effect of propane injection into a heatedformation.

[0503]FIG. 270 depicts the effect of butane injection into a heatedformation.

[0504]FIG. 271 depicts composition of gas produced from a formationversus time.

[0505]FIG. 272 depicts synthesis gas conversion versus time.

[0506]FIG. 273 depicts calculated equilibrium gas dry mole fractions fora reaction of coal with water.

[0507]FIG. 274 depicts calculated equilibrium gas wet mole fractions fora reaction of coal with water.

[0508]FIG. 275 depicts an embodiment of pyrolysis and synthesis gasproduction stages in a coal formation.

[0509]FIG. 276 depicts an embodiment of low temperature in situsynthesis gas production.

[0510]FIG. 277 depicts an embodiment of high temperature in situsynthesis gas production.

[0511]FIG. 278 depicts an embodiment of in situ synthesis gas productionin a hydrocarbon containing formation.

[0512]FIG. 279 depicts a plot of cumulative sorbed methane and carbondioxide versus pressure in a coal formation.

[0513]FIG. 280 depicts pressure at a wellhead as a function of time froma numerical simulation.

[0514]FIG. 281 depicts production rate of carbon dioxide and methane asa function of time from a numerical simulation.

[0515]FIG. 282 depicts cumulative methane produced and net carbondioxide injected as a function of time from a numerical simulation.

[0516]FIG. 283 depicts pressure at wellheads as a function of time froma numerical simulation.

[0517]FIG. 284 depicts production rate of carbon dioxide as a functionof time from a numerical simulation.

[0518]FIG. 285 depicts cumulative net carbon dioxide injected as afunction of time from a numerical simulation.

[0519]FIG. 286 depicts an embodiment of in situ synthesis gas productionintegrated with a Fischer-Tropsch process.

[0520]FIG. 287 depicts a comparison between numerical simulation dataand experimental field test data of synthesis gas composition producedas a function of time.

[0521]FIG. 288 depicts weight percentages of carbon compounds versuscarbon number produced from a heavy hydrocarbon containing formation.

[0522]FIG. 289 depicts weight percentages of carbon compounds producedfrom a heavy hydrocarbon containing formation for various pyrolysisheating rates and pressures.

[0523]FIG. 290 depicts H₂ mole percent in gases produced from heavyhydrocarbon drum experiments.

[0524]FIG. 291 depicts API gravity of liquids produced from heavyhydrocarbon drum experiments.

[0525]FIG. 292 depicts percentage of hydrocarbon fluid having carbonnumbers greater than 25 as a function of pressure and temperature foroil produced from a retort experiment.

[0526]FIG. 293 illustrates oil quality produced from a tar sandsformation as a function of pressure and temperature in a retortexperiment.

[0527]FIG. 294 illustrates an ethene to ethane ratio produced from a tarsands formation as a function of pressure and temperature in a retortexperiment.

[0528]FIG. 295 depicts the dependence of yield of equivalent liquidsproduced from a tar sands formation as a function of temperature andpressure in a retort experiment.

[0529]FIG. 296 illustrates a plot of percentage oil recovery versustemperature for a laboratory experiment and a simulation.

[0530]FIG. 297 depicts temperature versus time for a laboratoryexperiment and a simulation.

[0531]FIG. 298 depicts a plot of cumulative oil production versus timein a heavy hydrocarbon containing formation.

[0532]FIG. 299 depicts ratio of heat content of fluids produced from aheavy hydrocarbon containing formation to heat input versus time.

[0533]FIG. 300 depicts numerical simulation data of weight percentageversus carbon number for a heavy hydrocarbon containing formation.

[0534]FIG. 301 illustrates percentage cumulative oil recovery versustime for a simulation using horizontal heaters.

[0535]FIG. 302 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons in a simulation.

[0536]FIG. 303 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons with production inhibited for thefirst 500 days of heating in a simulation.

[0537]FIG. 304 depicts average pressure in a formation versus time in asimulation.

[0538]FIG. 305 illustrates cumulative oil production versus time for avertical producer and a horizontal producer in a simulation.

[0539]FIG. 306 illustrates percentage cumulative oil recovery versustime for three different horizontal producer well locations in asimulation.

[0540]FIG. 307 illustrates production rate versus time for heavyhydrocarbons and light hydrocarbons for middle and bottom producerlocations in a simulation.

[0541]FIG. 308 illustrates percentage cumulative oil recovery versustime in a simulation.

[0542]FIG. 309 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons in a simulation.

[0543]FIG. 310 illustrates a pattern of heater/producer wells used toheat a relatively permeable formation in a simulation.

[0544]FIG. 311 illustrates a pattern of heater/producer wells used inthe simulation with three heater/producer wells, a cold producer well,and three heater wells used to heat a relatively permeable formation ina simulation.

[0545]FIG. 312 illustrates a pattern of six heater wells and a coldproducer well used in a simulation.

[0546]FIG. 313 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 310.

[0547]FIG. 314 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 311.

[0548]FIG. 315 illustrates a plot of oil production versus time for thesimulation with the well pattern depicted in FIG. 312.

[0549]FIG. 316 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 310.

[0550]FIG. 317 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 311.

[0551]FIG. 318 illustrates gas production and water production versustime for the simulation with the well pattern depicted in FIG. 312.

[0552]FIG. 319 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 310.

[0553]FIG. 320 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 311.

[0554]FIG. 321 illustrates an energy ratio versus time for thesimulation with the well pattern depicted in FIG. 312.

[0555]FIG. 322 illustrates an average API gravity of produced fluidversus time for the simulations with the well patterns depicted in FIGS.310-312.

[0556]FIG. 323 depicts a heater well pattern used in a 3-D STARSsimulation.

[0557]FIG. 324 illustrates an energy out/energy in ratio versus time forproduction through a middle producer location in a simulation.

[0558]FIG. 325 illustrates percentage cumulative oil recovery versustime for production using a middle producer location and a bottomproducer location in a simulation.

[0559]FIG. 326 illustrates cumulative oil production versus time using amiddle producer location in a simulation.

[0560]FIG. 327 illustrates API gravity of oil produced and oilproduction rate for heavy hydrocarbons and light hydrocarbons for amiddle producer location in a simulation.

[0561]FIG. 328 illustrates cumulative oil production versus time for abottom producer location in a simulation.

[0562]FIG. 329 illustrates API gravity of oil produced and oilproduction rate for heavy hydrocarbons and light hydrocarbons for abottom producer location in a simulation.

[0563]FIG. 330 illustrates cumulative oil produced versus temperaturefor lab pyrolysis experiments and for a simulation.

[0564]FIG. 331 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced through a middle producerlocation in a simulation.

[0565]FIG. 332 illustrates cumulative oil production versus time for awider horizontal heater spacing with production through a middleproducer location in a simulation.

[0566]FIG. 333 depicts a heater well pattern used in a 3-D STARSsimulation.

[0567]FIG. 334 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced through a production welllocated in the middle of the formation in a simulation.

[0568]FIG. 335 illustrates cumulative oil production versus time for atriangular heater pattern used in a simulation.

[0569]FIG. 336 illustrates a pattern of wells used for a simulation.

[0570]FIG. 337 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for production using a bottomproduction well in a simulation.

[0571]FIG. 338 illustrates cumulative oil production versus time forproduction through a bottom production well in a simulation.

[0572]FIG. 339 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for production using a middleproduction well in a simulation.

[0573]FIG. 340 illustrates cumulative oil production versus time forproduction through a middle production well in a simulation.

[0574]FIG. 341 illustrates oil production rate versus time for heavyhydrocarbon production and light hydrocarbon production for productionusing a top production well in a simulation.

[0575]FIG. 342 illustrates cumulative oil production versus time forproduction through a top production well in a simulation.

[0576]FIG. 343 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons produced in a simulation.

[0577]FIG. 344 depicts an embodiment of a well pattern used in asimulation.

[0578]FIG. 345 illustrates oil production rate versus time for heavyhydrocarbons and light hydrocarbons for three production wells in asimulation.

[0579]FIG. 346 and FIG. 347 illustrate coke deposition near heaterwells.

[0580]FIG. 348 depicts a large pattern of heater and producer wells usedin a 3-D STARS simulation of an in situ process for a tar sandsformation.

[0581]FIG. 349 depicts net heater output versus time for the simulationwith the well pattern depicted in FIG. 348.

[0582]FIG. 350 depicts average pressure and average temperature versustime in a section of the formation for the simulation with the wellpattern depicted in FIG. 348.

[0583]FIG. 351 depicts oil production rate versus time as calculated inthe simulation with the well pattern depicted in FIG. 348.

[0584]FIG. 352 depicts cumulative oil production versus time ascalculated in the simulation with the well pattern depicted in FIG. 348.

[0585]FIG. 353 depicts gas production rate versus time as calculated inthe simulation with the well pattern depicted in FIG. 348.

[0586]FIG. 354 depicts cumulative gas production versus time ascalculated in the simulation with the well pattern depicted in FIG. 348.

[0587]FIG. 355 depicts energy ratio versus time as calculated in thesimulation with the well pattern depicted in FIG. 348.

[0588]FIG. 356 depicts average oil density versus time for thesimulation with the well pattern depicted in FIG. 348.

[0589]FIG. 357 depicts a schematic of a surface treatment configurationthat separates formation fluid as it is being produced from a formation.

[0590]FIG. 358 depicts a schematic of a treatment facility configurationthat heats a fluid for use in an in situ treatment process and/or atreatment facility configuration.

[0591]FIG. 359 depicts a schematic of an embodiment of a fractionatorthat separates component streams from a synthetic condensate.

[0592]FIG. 360 depicts a schematic of an embodiment of a series ofseparation units used to separate component streams from syntheticcondensate.

[0593]FIG. 361 depicts a schematic an embodiment of a series ofseparation units used to separate bottoms into fractions.

[0594]FIG. 362 depicts a schematic of an embodiment of a surfacetreatment configuration used to reactively distill a syntheticcondensate.

[0595]FIG. 363 depicts a schematic of an embodiment of a surfacetreatment configuration that separates formation fluid throughcondensation.

[0596]FIG. 364 depicts a schematic of an embodiment of a surfacetreatment configuration that hydrotreats untreated formation fluid.

[0597]FIG. 365 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins.

[0598]FIG. 366 depicts a schematic of an embodiment of a surfacetreatment configuration that removes a component and converts formationfluid into olefins.

[0599]FIG. 367 depicts a schematic of an embodiment of a surfacetreatment configuration that converts formation fluid into olefins usinga heating unit and a quenching unit.

[0600]FIG. 368 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0601]FIG. 369 depicts a schematic of an embodiment of a surfacetreatment configuration used to produce and separate ammonia.

[0602]FIG. 370 depicts a schematic of an embodiment of a surfacetreatment configuration that separates ammonia and hydrogen sulfide fromwater produced in the formation.

[0603]FIG. 371 depicts a schematic of an embodiment of a surfacetreatment configuration that produces ammonia on site.

[0604]FIG. 372 depicts a schematic of an embodiment of a surfacetreatment configuration used for the synthesis of urea.

[0605]FIG. 373 depicts a schematic of an embodiment of a surfacetreatment configuration that synthesizes ammonium sulfate.

[0606]FIG. 374 depicts an embodiment of surface treatment units used toseparate phenols from formation fluid.

[0607]FIG. 375 depicts a schematic of an embodiment of a surfacetreatment configuration used to separate BTEX compounds from formationfluid.

[0608]FIG. 376 depicts a schematic of an embodiment of a surfacetreatment configuration used to recover BTEX compounds from a naphthafraction.

[0609]FIG. 377 depicts a schematic of an embodiment of a surfacetreatment configuration that separates a component from a heart cut.

[0610]FIG. 378 illustrates experiments performed in a batch mode.

[0611]FIG. 379 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers.

[0612]FIG. 380 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0613]FIG. 381 depicts a side representation of an embodiment of an insitu conversion process system used to treat a thin rich formation.

[0614]FIG. 382 depicts a side representation of an embodiment of an insitu conversion process system.

[0615]FIG. 383 depicts a side representation of an embodiment of an insitu conversion process system with an installed upper perimeter barrierand an installed lower perimeter barrier.

[0616]FIG. 384 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in an equilateral trianglepattern.

[0617]FIG. 385 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers having arced portions,wherein the centers of the arced portions are in a square pattern.

[0618]FIG. 386 depicts a plan view representation of an embodiment oftreatment areas formed by perimeter barriers radially positioned arounda central point.

[0619]FIG. 387 depicts a plan view representation of a portion of atreatment area defined by a double ring of freeze wells.

[0620]FIG. 388 depicts a side representation of a freeze well that isdirectionally drilled in a formation so that the freeze well enters theformation in a first location and exits the formation in a secondlocation.

[0621]FIG. 389 depicts a side representation of freeze wells that form abarrier along sides and ends of a dipping hydrocarbon containing layerin a formation.

[0622]FIG. 390 depicts a representation of an embodiment of a freezewell and an embodiment of a heat source that may be used during an insitu conversion process.

[0623]FIG. 391 depicts an embodiment of a batch operated freeze well.

[0624]FIG. 392 depicts an embodiment of a batch operated freeze wellhaving an open wellbore portion.

[0625]FIG. 393 depicts a plan view representation of a circulated fluidrefrigeration system.

[0626]FIG. 394 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells versus well spacing.

[0627]FIG. 395 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system, wherein a cutaway view of the freeze wellis represented below ground surface.

[0628]FIG. 396 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0629]FIG. 397 depicts an embodiment of a freeze well for a circulatedliquid refrigeration system.

[0630]FIG. 398 depicts results of a simulation for Green River oil shalepresented as temperature versus time for a formation cooled with arefrigerant.

[0631]FIG. 399 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows slowly enough to allow for formation of an interconnected lowtemperature zone.

[0632]FIG. 400 depicts a plan view representation of low temperaturezones formed by freeze wells placed in a formation through which fluidflows at too high a flow rate to allow for formation of aninterconnected low temperature zone.

[0633]FIG. 401 depicts thermal simulation results of a heat sourcesurrounded by a ring of freeze wells.

[0634]FIG. 402 depicts a representation of an embodiment of a groundcover.

[0635]FIG. 403 depicts an embodiment of a treatment area surrounded by aring of dewatering wells.

[0636]FIG. 404A depicts an embodiment of a treatment area surrounded bytwo rings of dewatering wells.

[0637]FIG. 404B depicts an embodiment of a treatment area surrounded bytwo rings of freeze wells.

[0638]FIG. 405 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0639]FIG. 406 depicts an embodiment of a remediation process used totreat a treatment area.

[0640]FIG. 407 illustrates an embodiment of a temperature gradientformed in a section of heated formation.

[0641]FIG. 408 depicts an embodiment of a heated formation used forseparation of hydrocarbons and contaminants.

[0642]FIG. 409 depicts an embodiment for recovering heat from a heatedformation and transferring the heat to an above-ground processing unit.

[0643]FIG. 410 depicts an embodiment for recovering heat from oneformation and providing heat to another formation with an intermediateproduction step.

[0644]FIG. 411 depicts an embodiment for recovering heat from oneformation and providing heat to another formation in situ.

[0645]FIG. 412 depicts an embodiment of a region of reaction within aheated formation.

[0646]FIG. 413 depicts an embodiment of a conduit placed within a heatedformation.

[0647]FIG. 414 depicts an embodiment of a U-shaped conduit placed withina heated formation.

[0648]FIG. 415 depicts an embodiment for sequestration of carbon dioxidein a heated formation.

[0649]FIG. 416 depicts an embodiment for solution mining a formation.

[0650]FIG. 417 illustrates cumulative oil production and cumulative heatinput versus time using an in situ conversion process for solution minedoil shale and for non-solution mined oil shale.

[0651]FIG. 418 is a flow chart illustrating options for produced fluidsfrom a shut-in formation.

[0652]FIG. 419 illustrates a schematic of an embodiment of an injectionwellbore and a production wellbore.

[0653]FIG. 420 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0654]FIG. 421 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0655]FIG. 422 illustrates a cross-sectional representation of in situtreatment of a formation with steam injection according to oneembodiment.

[0656]FIG. 423 illustrates a schematic of a portion of a kerogen andliquid hydrocarbon containing formation.

[0657]FIG. 424 illustrates an expanded view of a selected section.

[0658]FIG. 425 depicts a schematic illustration of one embodiment ofproduction versus time or temperature from a production well as shown inFIG. 423.

[0659]FIG. 426 illustrates a schematic of a temperature profile of theRock-Eval pyrolysis process.

[0660]FIG. 427 illustrates a plan view of horizontal heater wells andhorizontal production wells.

[0661]FIG. 428 illustrates an end view schematic of the horizontalheater wells and horizontal production wells depicted in FIG. 427.

[0662]FIG. 429 illustrates a plan view of horizontal heater wells andvertical production wells.

[0663]FIG. 430 illustrates an end view schematic of the horizontalheater wells and vertical production wells depicted in FIG. 429.

[0664]FIG. 431 illustrates the production of condensables andnon-condensables per pattern as a function of time from an in situconversion process as calculated by a simulator.

[0665]FIG. 432 illustrates the total production of condensables andnon-condensables as a function of time from an in situ conversionprocess as calculated by a simulator.

[0666]FIG. 433 shows the annual heat injection rate per pattern versustime calculated by the simulator.

[0667]FIG. 434 illustrates a schematic of an embodiment of in situtreatment of an oil containing formation.

[0668]FIG. 435 depicts an embodiment for using acoustic reflections todetermine a location of a wellbore in a formation.

[0669]FIG. 436 depicts an embodiment for using acoustic reflections andmagnetic tracking to determine a location of a wellbore in a formation.

[0670]FIG. 437 depicts raw data obtained from an acoustic sensor in aformation.

[0671]FIGS. 438, 439, and 440 show magnetic field components as afunction of hole depth in neighboring observation wells.

[0672]FIG. 441 shows magnetic field components for a build-up section ofa wellbore.

[0673]FIG. 442 depicts a ratio of magnetic field components for abuild-up section of a wellbore.

[0674]FIG. 443 depicts a ratio of magnetic field components for abuild-up section of a wellbore.

[0675]FIG. 444 depicts comparisons of magnetic field componentsdetermined from experimental data and magnetic field components modeledusing analytical equations versus distance between wellbores.

[0676]FIG. 445 depicts the difference between the two curves in FIG.444.

[0677]FIG. 446 depicts comparisons of magnetic field componentsdetermined from experimental data and magnetic field components modeledusing analytical equations versus distance between wellbores.

[0678]FIG. 447 depicts the difference between the two curves in FIG.446.

[0679]FIG. 448 depicts a schematic representation of an embodiment of amagnetostatic drilling operation.

[0680]FIG. 449 depicts an embodiment of a section of a conduit with twomagnetic segments.

[0681]FIG. 450 depicts a schematic of a portion of a magnetic string.

[0682]FIG. 451 depicts an embodiment of a magnetic string.

[0683]FIG. 452 depicts magnetic field strength versus radial distanceusing analytical calculations.

[0684]FIG. 453 depicts an embodiment an opening in a hydrocarboncontaining formation that has been formed with a river crossing rig.

[0685]FIG. 454 depicts an embodiment for forming a portion of an openingin an overburden at a first end of the opening.

[0686]FIG. 455 depicts an embodiment of reinforcing material placed in aportion of an opening in an overburden at a first end of the opening.

[0687]FIG. 456 depicts an embodiment for forming an opening in ahydrocarbon layer and an overburden.

[0688]FIG. 457 depicts an embodiment of a reamed out portion of anopening in an overburden at a second end of the opening.

[0689]FIG. 458 depicts an embodiment of reinforcing material placed inthe reamed out portion of an opening.

[0690]FIG. 459 depicts an embodiment of reforming an opening through areinforcing material in a portion of an opening.

[0691]FIG. 460 depicts an embodiment for installing equipment into anopening.

[0692]FIG. 461 depicts an embodiment of a wellbore with a casing thatmay be energized to produce a magnetic field.

[0693]FIG. 462 depicts a plan view for an embodiment of forming one ormore wellbores using magnetic tracking of a previously formed wellbore.

[0694]FIG. 463 depicts another embodiment of a wellbore with a casingthat may be energized to produce a magnetic field.

[0695]FIG. 464 shows distances between wellbores and the surface usedfor a analytical equations.

[0696]FIG. 465 depicts an embodiment of a conductor-in-conduit heatsource with a lead-out conductor coupled to a sliding connector.

[0697]FIG. 466 depicts an embodiment of a conductor-in-conduit heatsource with lead-in and lead-out conductors in the overburden.

[0698]FIG. 467 depicts an embodiment of a heater in an open wellbore ofa hydrocarbon containing formation with a rich layer.

[0699]FIG. 468 depicts an embodiment of a heater in an open wellbore ofa hydrocarbon containing formation with an expanded rich layer.

[0700]FIG. 469 depicts calculations of wellbore radius change versustime for heating in an open wellbore.

[0701]FIG. 470 depicts calculations of wellbore radius change versustime for heating in an open wellbore.

[0702]FIG. 471 depicts an embodiment of a heater in an open wellbore ofa hydrocarbon containing formation with an expanded wellbore proximate arich layer.

[0703]FIG. 472 depicts an embodiment of a heater in an open wellborewith a liner placed in the opening.

[0704]FIG. 473 depicts an embodiment of a heater in an open wellborewith a liner placed in the opening and the formation expanded againstthe liner.

[0705]FIG. 474 depicts maximum stress and hole size versus richness forcalculations of heating in an open wellbore.

[0706]FIG. 475 depicts an embodiment of a plan view of a pattern ofheaters for heating a hydrocarbon containing formation.

[0707]FIG. 476 depicts an embodiment of a plan view of a pattern ofheaters for heating a hydrocarbon containing formation.

[0708]FIG. 477 shows DC resistivity versus temperature for a 1% carbonsteel temperature limited heater.

[0709]FIG. 478 shows relative permeability versus temperature for a 1%carbon steel temperature limited heater.

[0710]FIG. 479 shows skin depth versus temperature for a 1% carbon steeltemperature limited heater at 60 Hz.

[0711]FIG. 480 shows AC resistance versus temperature for a 1% carbonsteel temperature limited heater at 60 Hz.

[0712]FIG. 481 shows heater power per meter versus temperature for a 1%carbon steel rod at 350 A at 60 Hz.

[0713]FIG. 482 depicts an embodiment for forming a composite conductor.

[0714]FIG. 483 depicts an embodiment of an inner conductor and an outerconductor formed by a tube-in-tube milling process.

[0715]FIG. 484 depicts an embodiment of a temperature limited heater.

[0716]FIG. 485 depicts an embodiment of a temperature limited heater.

[0717]FIG. 486 depicts AC resistance versus temperature for a 1.5 cmdiameter iron conductor.

[0718]FIG. 487 depicts AC resistance versus temperature for a 1.5 cmdiameter composite conductor of iron and copper.

[0719]FIG. 488 depicts AC resistance versus temperature for a 1.3 cmdiameter composite conductor of iron and copper and a 1.5 cm diametercomposite conductor of iron and copper.

[0720]FIG. 489 depicts an embodiment of a temperature limited heater.

[0721]FIG. 490 depicts an embodiment of a temperature limited heater.

[0722]FIG. 491 depicts an embodiment of a temperature limited heater.

[0723]FIG. 492 depicts an embodiment of a conductor-in-conduittemperature limited heater.

[0724]FIG. 493 depicts an embodiment of a conductor-in-conduittemperature limited heater.

[0725]FIG. 494 depicts an embodiment of a conductor-in-conduittemperature limited heater with an insulated conductor as the conductor.

[0726]FIG. 495 depicts an embodiment of an insulatedconductor-in-conduit temperature limited heater.

[0727]FIG. 496 depicts an embodiment of an insulatedconductor-in-conduit temperature limited heater.

[0728]FIG. 497 depicts an embodiment of a temperature limited heater.

[0729]FIG. 498 depicts an embodiment of an “S” bend for a heater.

[0730]FIG. 499 depicts an embodiment of a three-phase temperaturelimited heater.

[0731]FIG. 500 depicts an embodiment of a three-phase temperaturelimited heater.

[0732]FIG. 501 depicts an embodiment of a temperature limited heaterwith current return through the earth formation.

[0733]FIG. 502 depicts an embodiment of a three-phase temperaturelimited heater with current connection through the earth formation.

[0734]FIG. 503 depicts a plan view of the embodiment of FIG. 502.

[0735]FIG. 504 depicts heater temperature versus depth for heaters usedin a simulation for heating oil shale.

[0736]FIG. 505 depicts heat flux versus time for heaters used in asimulation for heating oil shale.

[0737]FIG. 506 depicts accumulated heat input versus time in asimulation for heating oil shale.

[0738]FIG. 507 depicts AC resistance versus temperature using ananalytical solution.

[0739]FIG. 508 depicts an embodiment of a freeze well for a hydrocarboncontaining formation.

[0740]FIG. 509 depicts an embodiment of a freeze well for inhibitingwater flow.

[0741] While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

[0742] The following description generally relates to systems andmethods for treating a hydrocarbon containing formation (e.g., aformation containing coal (including lignite, sapropelic coal, etc.),oil shale, carbonaceous shale, shungites, kerogen, bitumen, oil, kerogenand oil in a low permeability matrix, heavy hydrocarbons, asphaltites,natural mineral waxes, formations wherein kerogen is blocking productionof other hydrocarbons, etc.). Such formations may be treated to yieldrelatively high quality hydrocarbon products, hydrogen, and otherproducts.

[0743] “Hydrocarbons” are generally defined as molecules formedprimarily by carbon and hydrogen atoms. Hydrocarbons may also includeother elements, such as, but not limited to, halogens, metallicelements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but arenot limited to, kerogen, bitumen, pyrobitumen, oils, natural mineralwaxes, and asphaltites. Hydrocarbons may be located within or adjacentto mineral matrices within the earth. Matrices may include, but are notlimited to, sedimentary rock, sands, silicilytes, carbonates,diatomites, and other porous media. “Hydrocarbon fluids” are fluids thatinclude hydrocarbons. Hydrocarbon fluids may include, entrain, or beentrained in non-hydrocarbon fluids (e.g., hydrogen (“H₂”), nitrogen(“N₂”), carbon monoxide, carbon dioxide, hydrogen sulfide, water, andammonia).

[0744] A “formation” includes one or more hydrocarbon containing layers,one or more non-hydrocarbon layers, an overburden, and/or anunderburden. An “overburden” and/or an “underburden” includes one ormore different types of impermeable materials. For example, overburdenand/or underburden may include rock, shale, mudstone, or wet/tightcarbonate (i.e., an impermeable carbonate without hydrocarbons). In someembodiments of in situ conversion processes, an overburden and/or anunderburden may include a hydrocarbon containing layer or hydrocarboncontaining layers that are relatively impermeable and are not subjectedto temperatures during in situ conversion processing that results insignificant characteristic changes of the hydrocarbon containing layersof the overburden and/or underburden. For example, an underburden maycontain shale or mudstone. In some cases, the overburden and/orunderburden may be somewhat permeable.

[0745] “Kerogen” is a solid, insoluble hydrocarbon that has beenconverted by natural degradation (e.g., by diagenesis) and thatprincipally contains carbon, hydrogen, nitrogen, oxygen, and sulfur.Coal and oil shale are typical examples of materials that containkerogens. “Bitumen” is a non-crystalline solid or viscous hydrocarbonmaterial that is substantially soluble in carbon disulfide. “Oil” is afluid containing a mixture of condensable hydrocarbons.

[0746] The terms “formation fluids” and “produced fluids” refer tofluids removed from a hydrocarbon containing formation and may includepyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water(steam). The term “mobilized fluid” refers to fluids within theformation that are able to flow because of thermal treatment of theformation. Formation fluids may include hydrocarbon fluids as well asnon-hydrocarbon fluids.

[0747] “Carbon number” refers to a number of carbon atoms within amolecule. A hydrocarbon fluid may include various hydrocarbons havingvarying numbers of carbon atoms. The hydrocarbon fluid may be describedby a carbon number distribution. Carbon numbers and/or carbon numberdistributions may be determined by true boiling point distributionand/or gas-liquid chromatography.

[0748] A “heat source” is any system for providing heat to at least aportion of a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and/or a conductordisposed within a conduit, as described in embodiments herein. A heatsource may also include heat sources that generate heat by burning afuel external to or within a formation, such as surface burners,downhole gas burners, flameless distributed combustors, and naturaldistributed combustors, as described in embodiments herein. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer media that directly or indirectly heats the formation. It is tobe understood that one or more heat sources that are applying heat to aformation may use different sources of energy. Thus, for example, for agiven formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (e.g., chemical reactions, solar energy, wind energy, biomass,or other sources of renewable energy). A chemical reaction may includean exothermic reaction (e.g., an oxidation reaction). A heat source mayalso include a heater that may provide heat to a zone proximate and/orsurrounding a heating location such as a heater well.

[0749] A “heater” is any system for generating heat in a well or a nearwellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors (e.g., natural distributed combustors) thatreact with material in or produced from a formation, and/or combinationsthereof. A “unit of heat sources” refers to a number of heat sourcesthat form a template that is repeated to create a pattern of heatsources within a formation.

[0750] The term “wellbore” refers to a hole in a formation made bydrilling or insertion of a conduit into the formation. A wellbore mayhave a substantially circular cross section, or other cross-sectionalshapes (e.g., circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes). As used herein, the terms “well” and“opening,” when referring to an opening in the formation may be usedinterchangeably with the term “wellbore.”

[0751] “Natural distributed combustor” refers to a heater that uses anoxidant to oxidize at least a portion of the carbon in the formation togenerate heat, and wherein the oxidation takes place in a vicinityproximate a wellbore. Most of the combustion products produced in thenatural distributed combustor are removed through the wellbore.

[0752] “Orifices” refer to openings (e.g., openings in conduits) havinga wide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

[0753] “Reaction zone” refers to a volume of a hydrocarbon containingformation that is subjected to a chemical reaction such as an oxidationreaction.

[0754] “Insulated conductor” refers to any elongated material that isable to conduct electricity and that is covered, in whole or in part, byan electrically insulating material. The term “self-controls” refers tocontrolling an output of a heater without external control of any type.

[0755] “Pyrolysis” is the breaking of chemical bonds due to theapplication of heat. For example, pyrolysis may include transforming acompound into one or more other substances by heat alone. Heat may betransferred to a section of the formation to cause pyrolysis.

[0756] “Pyrolyzation fluids” or “pyrolysis products” refers to fluidproduced substantially during pyrolysis of hydrocarbons. Fluid producedby pyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation(e.g., a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

[0757] “Cracking” refers to a process involving decomposition andmolecular recombination of organic compounds to produce a greater numberof molecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

[0758] “Superposition of heat” refers to providing heat from two or moreheat sources to a selected section of a formation such that thetemperature of the formation at least at one location between the heatsources is influenced by the heat sources.

[0759] “Fingering” refers to injected fluids bypassing portions of aformation because of variations in transport characteristics of theformation (e.g., permeability or porosity).

[0760] “Thermal conductivity” is a property of a material that describesthe rate at which heat flows, in steady state, between two surfaces ofthe material for a given temperature difference between the twosurfaces.

[0761] “Fluid pressure” is a pressure generated by a fluid within aformation. “Lithostatic pressure” (sometimes referred to as “lithostaticstress”) is a pressure within a formation equal to a weight per unitarea of an overlying rock mass. “Hydrostatic pressure” is a pressurewithin a formation exerted by a column of water.

[0762] “Condensable hydrocarbons” are hydrocarbons that condense at 25°C. at one atmosphere absolute pressure. Condensable hydrocarbons mayinclude a mixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0763] “Olefins” are molecules that include unsaturated hydrocarbonshaving one or more non-aromatic carbon-to-carbon double bonds.

[0764] “Urea” describes a compound represented by the molecular formulaof NH₂—CO—NH₂. Urea may be used as a fertilizer.

[0765] “Synthesis gas” is a mixture including hydrogen and carbonmonoxide used for synthesizing a wide range of compounds. Additionalcomponents of synthesis gas may include water, carbon dioxide, nitrogen,methane, and other gases. Synthesis gas may be generated by a variety ofprocesses and feedstocks.

[0766] “Reforming” is a reaction of hydrocarbons (such as methane ornaphtha) with steam to produce CO and H₂ as major products. Generally,it is conducted in the presence of a catalyst, although it can beperformed thermally without the presence of a catalyst.

[0767] “Sequestration” refers to storing a gas that is a by-product of aprocess rather than venting the gas to the atmosphere.

[0768] “Dipping” refers to a formation that slopes downward or inclinesfrom a plane parallel to the earth's surface, assuming the plane is flat(i.e., a “horizontal” plane). A “dip” is an angle that a stratum orsimilar feature makes with a horizontal plane. A “steeply dipping”hydrocarbon containing formation refers to a hydrocarbon containingformation lying at an angle of at least 20° from a horizontal plane.“Down dip” refers to downward along a direction parallel to a dip in aformation. “Up dip” refers to upward along a direction parallel to a dipof a formation. “Strike” refers to the course or bearing of hydrocarbonmaterial that is normal to the direction of dip.

[0769] “Subsidence” is a downward movement of a portion of a formationrelative to an initial elevation of the surface.

[0770] “Thickness” of a layer refers to the thickness of a cross sectionof a layer, wherein the cross section is normal to a face of the layer.

[0771] “Coring” is a process that generally includes drilling a holeinto a formation and removing a substantially solid mass of theformation from the hole.

[0772] A “surface unit” is an ex situ treatment unit.

[0773] “Middle distillates” refers to hydrocarbon mixtures with aboiling point range that corresponds substantially with that of keroseneand gas oil fractions obtained in a conventional atmosphericdistillation of crude oil material. The middle distillate boiling pointrange may include temperatures between about 150° C. and about 360° C.,with a fraction boiling point between about 200° C. and about 360° C.Middle distillates may be referred to as gas oil.

[0774] A “boiling point cut” is a hydrocarbon liquid fraction that maybe separated from hydrocarbon liquids when the hydrocarbon liquids areheated to a boiling point range of the fraction.

[0775] “Selected mobilized section” refers to a section of a formationthat is at an average temperature within a mobilization temperaturerange. “Selected pyrolyzation section” refers to a section of aformation (e.g., a relatively permeable formation such as a tar sandsformation) that is at an average temperature within a pyrolyzationtemperature range.

[0776] “Enriched air” refers to air having a larger mole fraction ofoxygen than air in the atmosphere. Enrichment of air is typically doneto increase its combustion-supporting ability.

[0777] “Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavyhydrocarbons may include highly viscous hydrocarbon fluids such as heavyoil, tar, and/or asphalt. Heavy hydrocarbons may include carbon andhydrogen, as well as smaller concentrations of sulfur, oxygen, andnitrogen. Additional elements may also be present in heavy hydrocarbonsin trace amounts. Heavy hydrocarbons may be classified by API gravity.Heavy hydrocarbons generally have an API gravity below about 20°. Heavyoil, for example, generally has an API gravity of about 10-20°, whereastar generally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may also include aromatics or other complex ringhydrocarbons.

[0778] Heavy hydrocarbons may be found in a relatively permeableformation. The relatively permeable formation may include heavyhydrocarbons entrained in, for example, sand or carbonate. “Relativelypermeable” is defined, with respect to formations or portions thereof,as an average permeability of 10 millidarcy or more (e.g., 10 or 100millidarcy). “Relatively low permeability” is defined, with respect toformations or portions thereof, as an average permeability of less thanabout 10 millidarcy. One darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

[0779] “Tar” is a viscous hydrocarbon that generally has a viscositygreater than about 10,000 centipoise at 15° C. The specific gravity oftar generally is greater than 1.000. Tar may have an API gravity lessthan 10°.

[0780] A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (e.g.,sand or carbonate).

[0781] In some cases, a portion or all of a hydrocarbon portion of arelatively permeable formation may be predominantly heavy hydrocarbonsand/or tar with no supporting mineral grain framework and only floating(or no) mineral matter (e.g., asphalt lakes).

[0782] Certain types of formations that include heavy hydrocarbons mayalso be, but are not limited to, natural mineral waxes (e.g.,ozocerite), or natural asphaltites (e.g., gilsonite, albertite,impsonite, wurtzilite, grahamite, and glance pitch). “Natural mineralwaxes” typically occur in substantially tubular veins that may beseveral meters wide, several kilometers long, and hundreds of metersdeep. “Natural asphaltites” include solid hydrocarbons of an aromaticcomposition and typically occur in large veins. In situ recovery ofhydrocarbons from formations such as natural mineral waxes and naturalasphaltites may include melting to form liquid hydrocarbons and/orsolution mining of hydrocarbons from the formations.

[0783] “Upgrade” refers to increasing the quality of hydrocarbons. Forexample, upgrading heavy hydrocarbons may result in an increase in theAPI gravity of the heavy hydrocarbons.

[0784] “Off peak” times refers to times of operation when utility energyis less commonly used and, therefore, less expensive.

[0785] “Low viscosity zone” refers to a section of a formation where atleast a portion of the fluids are mobilized.

[0786] “Thermal fracture” refers to fractures created in a formationcaused by expansion or contraction of a formation and/or fluids withinthe formation, which is in turn caused by increasing/decreasing thetemperature of the formation and/or fluids within the formation, and/orby increasing/decreasing a pressure of fluids within the formation dueto heating.

[0787] “Vertical hydraulic fracture” refers to a fracture at leastpartially propagated along a vertical plane in a formation, wherein thefracture is created through injection of fluids into a formation.

[0788] Hydrocarbons in formations may be treated in various ways toproduce many different products. In certain embodiments, such formationsmay be treated in stages. FIG. 1 illustrates several stages of heating ahydrocarbon containing formation. FIG. 1 also depicts an example ofyield (barrels of oil equivalent per ton) (y axis) of formation fluidsfrom a hydrocarbon containing formation versus temperature (° C.) (xaxis) of the formation.

[0789] Desorption of methane and vaporization of water occurs duringstage 1 heating. Heating of the formation through stage 1 may beperformed as quickly as possible. For example, when a hydrocarboncontaining formation is initially heated, hydrocarbons in the formationmay desorb adsorbed methane. The desorbed methane may be produced fromthe formation. If the hydrocarbon containing formation is heatedfurther, water within the hydrocarbon containing formation may bevaporized. Water may occupy, in some hydrocarbon containing formations,between about 10% to about 50% of the pore volume in the formation. Inother formations, water may occupy larger or smaller portions of thepore volume. Water typically is vaporized in a formation between about160° C. and about 285° C. for pressures of about 6 bars absolute to 70bars absolute. In some embodiments, the vaporized water may producewettability changes in the formation and/or increase formation pressure.The wettability changes and/or increased pressure may affect pyrolysisreactions or other reactions in the formation. In certain embodiments,the vaporized water may be produced from the formation. In otherembodiments, the vaporized water may be used for steam extraction and/ordistillation in the formation or outside the formation. Removing thewater from and increasing the pore volume in the formation may increasethe storage space for hydrocarbons within the pore volume.

[0790] After stage 1 heating, the formation may be heated further, suchthat a temperature within the formation reaches (at least) an initialpyrolyzation temperature (e.g., a temperature at the lower end of thetemperature range shown as stage 2). Hydrocarbons within the formationmay be pyrolyzed throughout stage 2. A pyrolysis temperature range mayvary depending on types of hydrocarbons within the formation. Apyrolysis temperature range may include temperatures between about 250°C. and about 900° C. A pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, a pyrolysis temperature rangefor producing desired products may include temperatures between about250° C. to about 400° C. If a temperature of hydrocarbons in a formationis slowly raised through a temperature range from about 250° C. to about400° C., production of pyrolysis products may be substantially completewhen the temperature approaches 400° C. Heating the hydrocarboncontaining formation with a plurality of heat sources may establishthermal gradients around the heat sources that slowly raise thetemperature of hydrocarbons in the formation through a pyrolysistemperature range.

[0791] In some in situ conversion embodiments, a temperature of thehydrocarbons to be subjected to pyrolysis may not be slowly increasedthroughout a temperature range from about 250° C. to about 400° C. Thehydrocarbons in the formation may be heated to a desired temperature(e.g., about 325° C.). Other temperatures may be selected as the desiredtemperature. Superposition of heat from heat sources may allow thedesired temperature to be relatively quickly and efficiently establishedin the formation. Energy input into the formation from the heat sourcesmay be adjusted to maintain the temperature in the formationsubstantially at the desired temperature. The hydrocarbons may bemaintained substantially at the desired temperature until pyrolysisdeclines such that production of desired formation fluids from theformation becomes uneconomical. Parts of a formation that are subjectedto pyrolysis may include regions brought into a pyrolysis temperaturerange by heat transfer from only one heat source.

[0792] Formation fluids including pyrolyzation fluids may be producedfrom the formation. The pyrolyzation fluids may include, but are notlimited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide,hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof. As thetemperature of the formation increases, the amount of condensablehydrocarbons in the produced formation fluid tends to decrease. At hightemperatures, the formation may produce mostly methane and/or hydrogen.If a hydrocarbon containing formation is heated throughout an entirepyrolysis range, the formation may produce only small amounts ofhydrogen towards an upper limit of the pyrolysis range. After all of theavailable hydrogen is depleted, a minimal amount of fluid productionfrom the formation will typically occur.

[0793] After pyrolysis of hydrocarbons, a large amount of carbon andsome hydrogen may still be present in the formation. A significantportion of remaining carbon in the formation can be produced from theformation in the form of synthesis gas. Synthesis gas generation maytake place during stage 3 heating depicted in FIG. 1. Stage 3 mayinclude heating a hydrocarbon containing formation to a temperaturesufficient to allow synthesis gas generation. For example, synthesis gasmay be produced within a temperature range from about 400° C. to about1200° C. The temperature of the formation when the synthesis gasgenerating fluid is introduced to the formation may determine thecomposition of synthesis gas produced within the formation. If asynthesis gas generating fluid is introduced into a formation at atemperature sufficient to allow synthesis gas generation, synthesis gasmay be generated within the formation. The generated synthesis gas maybe removed from the formation through a production well or productionwells. A large volume of synthesis gas may be produced during generationof synthesis gas.

[0794] Total energy content of fluids produced from a hydrocarboncontaining formation may stay relatively constant throughout pyrolysisand synthesis gas generation. During pyrolysis at relatively lowformation temperatures, a significant portion of the produced fluid maybe condensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

[0795]FIG. 2 depicts a van Krevelen diagram. The van Krevelen diagram isa plot of atomic hydrogen to carbon ratio (y axis) versus atomic oxygento carbon ratio (x axis) for various types of kerogen. The van Krevelendiagram shows the maturation sequence for various types of kerogen thattypically occurs over geologic time due to temperature, pressure, andbiochemical degradation. The maturation sequence may be accelerated byheating in situ at a controlled rate and/or a controlled pressure.

[0796] A van Krevelen diagram may be useful for selecting a resource forpracticing various embodiments. Treating a formation containing kerogenin region 500 may produce carbon dioxide, non-condensable hydrocarbons,hydrogen, and water, along with a relatively small amount of condensablehydrocarbons. Treating a formation containing kerogen in region 502 mayproduce condensable and non-condensable hydrocarbons, carbon dioxide,hydrogen, and water. Treating a formation containing kerogen in region504 will in many instances produce methane and hydrogen. A formationcontaining kerogen in region 502 may be selected for treatment becausetreating region 502 kerogen may produce large quantities of valuablehydrocarbons, and low quantities of undesirable products such as carbondioxide and water. A region 502 kerogen may produce large quantities ofvaluable hydrocarbons and low quantities of undesirable products becausethe region 502 kerogen has already undergone dehydration and/ordecarboxylation over geological time. In addition, region 502 kerogencan be further treated to make other useful products (e.g., methane,hydrogen, and/or synthesis gas) as the kerogen transforms to region 504kerogen.

[0797] If a formation containing kerogen in region 500 or region 502 isselected for in situ conversion, in situ thermal treatment mayaccelerate maturation of the kerogen along paths represented by arrowsin FIG. 2. For example, region 500 kerogen may transform to region 502kerogen and possibly then to region 504 kerogen. Region 502 kerogen maytransform to region 504 kerogen. In situ conversion may expeditematuration of kerogen and allow production of valuable products from thekerogen.

[0798] If region 500 kerogen is treated, a substantial amount of carbondioxide may be produced due to decarboxylation of hydrocarbons in theformation. In addition to carbon dioxide, region 500 kerogen may producesome hydrocarbons (e.g., methane). Treating region 500 kerogen mayproduce substantial amounts of water due to dehydration of kerogen inthe formation. Production of water from kerogen may leave hydrocarbonsremaining in the formation enriched in carbon. Oxygen content of thehydrocarbons may decrease faster than hydrogen content of thehydrocarbons during production of such water and carbon dioxide from theformation. Therefore, production of such water and carbon dioxide fromregion 500 kerogen may result in a larger decrease in the atomic oxygento carbon ratio than a decrease in the atomic hydrogen to carbon ratio(see region 500 arrows in FIG. 2 which depict more horizontal thanvertical movement).

[0799] If region 502 kerogen is treated, some of the hydrocarbons in theformation may be pyrolyzed to produce condensable and non-condensablehydrocarbons. For example, treating region 502 kerogen may result inproduction of oil from hydrocarbons, as well as some carbon dioxide andwater. In situ conversion of region 502 kerogen may producesignificantly less carbon dioxide and water than is produced during insitu conversion of region 500 kerogen. Therefore, the atomic hydrogen tocarbon ratio of the kerogen may decrease rapidly as the kerogen inregion 502 is treated. The atomic oxygen to carbon ratio of region 502kerogen may decrease much slower than the atomic hydrogen to carbonratio of region 502 kerogen.

[0800] Kerogen in region 504 may be treated to generate methane andhydrogen. For example, if such kerogen was previously treated (e.g., itwas previously region 502 kerogen), then after pyrolysis longerhydrocarbon chains of the hydrocarbons may have cracked and beenproduced from the formation. Carbon and hydrogen, however, may still bepresent in the formation.

[0801] If kerogen in region 504 were heated to a synthesis gasgenerating temperature and a synthesis gas generating fluid (e.g.,steam) were added to the region 504 kerogen, then at least a portion ofremaining hydrocarbons in the formation may be produced from theformation in the form of synthesis gas. For region 504 kerogen, theatomic hydrogen to carbon ratio and the atomic oxygen to carbon ratio inthe hydrocarbons may significantly decrease as the temperature rises.Hydrocarbons in the formation may be transformed into relatively purecarbon in region 504. Heating region 504 kerogen to still highertemperatures will tend to transform such kerogen into graphite 506.

[0802] A hydrocarbon containing formation may have a number ofproperties that depend on a composition of the hydrocarbons within theformation. Such properties may affect the composition and amount ofproducts that are produced from a hydrocarbon containing formationduring in situ conversion. Properties of a hydrocarbon containingformation may be used to determine if and/or how a hydrocarboncontaining formation is to be subjected to in situ conversion.

[0803] Kerogen is composed of organic matter that has been transformeddue to a maturation process. Hydrocarbon containing formations thatinclude kerogen may include, but are not limited to, coal formations andoil shale formations. Examples of hydrocarbon containing formations thatmay not include significant amounts of kerogen are formations containingoil or heavy hydrocarbons (e.g., tar sands). The maturation process forkerogen may include two stages: a biochemical stage and a geochemicalstage. The biochemical stage typically involves degradation of organicmaterial by aerobic and/or anaerobic organisms. The geochemical stagetypically involves conversion of organic matter due to temperaturechanges and significant pressures. During maturation, oil and gas may beproduced as the organic matter of the kerogen is transformed.

[0804] The van Krevelen diagram shown in FIG. 2 classifies variousnatural deposits of kerogen. For example, kerogen may be classified intofour distinct groups: type I, type II, type III, and type IV, which areillustrated by the four branches of the van Krevelen diagram. The vanKrevelen diagram shows the maturation sequence for kerogen thattypically occurs over geological time due to temperature and pressure.Classification of kerogen type may depend upon precursor materials ofthe kerogen. The precursor materials transform over time into macerals.Macerals are microscopic structures that have different structures andproperties depending on the precursor materials from which they arederived. Oil shale may be described as a kerogen type I or type II, andmay primarily contain macerals from the liptinite group. Liptinites arederived from plants, specifically the lipid rich and resinous parts. Theconcentration of hydrogen within liptinite may be as high as 9 weight %.In addition, liptinite has a relatively high hydrogen to carbon ratioand a relatively low atomic oxygen to carbon ratio.

[0805] A type I kerogen may be classified as an alginite, since type Ikerogen developed primarily from algal bodies. Type I kerogen may resultfrom deposits made in lacustrine environments. Type II kerogen maydevelop from organic matter that was deposited in marine environments.

[0806] Type III kerogen may generally include vitrinite macerals.Vitrinite is derived from cell walls and/or woody tissues (e.g., stems,branches, leaves, and roots of plants). Type III kerogen may be presentin most humic coals. Type III kerogen may develop from organic matterthat was deposited in swamps. Type IV kerogen includes the inertinitemaceral group. The inertinite maceral group is composed of plantmaterial such as leaves, bark, and stems that have undergone oxidationduring the early peat stages of burial diagenesis. Inertinite maceral ischemically similar to vitrinite, but has a high carbon and low hydrogencontent.

[0807] The dashed lines in FIG. 2 correspond to vitrinite reflectance.Vitrinite reflectance is a measure of maturation. As kerogen undergoesmaturation, the composition of the kerogen usually changes due toexpulsion of volatile matter (e.g., carbon dioxide, methane, and oil)from the kerogen. Rank classifications of kerogen indicate the level towhich kerogen has matured. For example, as kerogen undergoes maturation,the rank of kerogen increases. As rank increases, the volatile matterwithin, and producible from, the kerogen tends to decrease. In addition,the moisture content of kerogen generally decreases as the rankincreases. At higher ranks, the moisture content may reach a relativelyconstant value. Higher rank kerogens that have undergone significantmaturation, such as semi-anthracite or anthracite coal, tend to have ahigher carbon content and a lower volatile matter content than lowerrank kerogens such as lignite.

[0808] Rank stages of coal formations include the followingclassifications, which are listed in order of increasing rank andmaturity for type III kerogen: wood, peat, lignite, sub-bituminous coal,high volatile bituminous coal, medium volatile bituminous coal, lowvolatile bituminous coal, semi-anthracite, and anthracite. As rankincreases, kerogen tends to exhibit an increase in aromatic nature.

[0809] Hydrocarbon containing formations may be selected for in situconversion based on properties of at least a portion of the formation.For example, a formation may be selected based on richness, thickness,and/or depth (i.e., thickness of overburden) of the formation. Inaddition, the types of fluids producible from the formation may be afactor in the selection of a formation for in situ conversion. Incertain embodiments, the quality of the fluids to be produced may beassessed in advance of treatment. Assessment of the products that may beproduced from a formation may generate significant cost savings sinceonly formations that will produce desired products need to be subjectedto in situ conversion. Properties that may be used to assesshydrocarbons in a formation include, but are not limited to, an amountof hydrocarbon liquids that may be produced from the hydrocarbons, alikely API gravity of the produced hydrocarbon liquids, an amount ofhydrocarbon gas producible from the formation, and/or an amount ofcarbon dioxide and water that in situ conversion will generate.

[0810] Another property that may be used to assess the quality-of fluidsproduced from certain kerogen containing formations is vitrinitereflectance. Such formations include, but are not limited to, coalformations and oil shale formations. Hydrocarbon containing formationsthat include kerogen may be assessed/selected for treatment based on avitrinite reflectance of the kerogen. Vitrinite reflectance is oftenrelated to a hydrogen to carbon atomic ratio of a kerogen and an oxygento carbon atomic ratio of the kerogen, as shown by the dashed lines inFIG. 2. A van Krevelen diagram may be useful in selecting a resource foran in situ conversion process.

[0811] Vitrinite reflectance of a kerogen in a hydrocarbon containingformation may indicate which fluids are producible from a formation uponheating. For example, a vitrinite reflectance of approximately 0.5% toapproximately 1.5% may indicate that the kerogen will produce a largequantity of condensable fluids. In addition, a vitrinite reflectance ofapproximately 1.5% to 3.0% may indicate a kerogen in region 504 asdescribed above. If a hydrocarbon containing formation having suchkerogen is heated, a significant amount (e.g., a majority) of the fluidproduced by such heating may include methane and hydrogen. The formationmay be used to generate synthesis gas if the temperature is raisedsufficiently high and a synthesis gas generating fluid is introducedinto the formation.

[0812] A kerogen containing formation to be subjected to in situconversion may be chosen based on a vitrinite reflectance. The vitrinitereflectance of the kerogen may indicate that the formation will producehigh quality fluids when subjected to in situ conversion. In some insitu conversion embodiments, a portion of the kerogen containingformation to be subjected to in situ conversion may have a vitrinitereflectance in a range between about 0.2% and about 3.0%. In some insitu conversion embodiments, a portion of the kerogen containingformation may have a vitrinite reflectance from about 0.5% to about2.0%. In some in situ conversion embodiments, a portion of the kerogencontaining formation may have a vitrinite reflectance from about 0.5% toabout 1.0%.

[0813] In some in situ conversion embodiments, a hydrocarbon containingformation may be selected for treatment based on a hydrogen contentwithin the hydrocarbons in the formation. For example, a method oftreating a hydrocarbon containing formation may include selecting aportion of the hydrocarbon containing formation for treatment havinghydrocarbons with a hydrogen content greater than about 3 weight %, 3.5weight %, or 4 weight % when measured on a dry, ash-free basis. Inaddition, a selected section of a hydrocarbon containing formation mayinclude hydrocarbons with an atomic hydrogen to carbon ratio that fallswithin a range from about 0.5 to about 2, and in many instances fromabout 0.70 to about 1.65.

[0814] Hydrogen content of a hydrocarbon containing formation maysignificantly influence a composition of hydrocarbon fluids produciblefrom the formation. Pyrolysis of hydrocarbons within heated portions ofthe formation may generate hydrocarbon fluids that include a double bondor a radical. Hydrogen within the formation may reduce the double bondto a single bond. Reaction of generated hydrocarbon fluids with eachother and/or with additional components in the formation may beinhibited. For example, reduction of a double bond of the generatedhydrocarbon fluids to a single bond may reduce polymerization of thegenerated hydrocarbons. Such polymerization may reduce the amount offluids produced and may reduce the quality of fluid produced from theformation.

[0815] Hydrogen within the formation may neutralize radicals in thegenerated hydrocarbon fluids. Hydrogen present in the formation mayinhibit reaction of hydrocarbon fragments by transforming thehydrocarbon fragments into relatively short chain hydrocarbon fluids.The hydrocarbon fluids may enter a vapor phase. Vapor phase hydrocarbonsmay move relatively easily through the formation to production wells.Increase in the hydrocarbon fluids in the vapor phase may significantlyreduce a potential for producing less desirable products within theselected section of the formation.

[0816] A lack of bound and free hydrogen in the formation may negativelyaffect the amount and quality of fluids that can be produced from theformation. If too little hydrogen is naturally present, then hydrogen orother reducing fluids may be added to the formation.

[0817] When heating a portion of a hydrocarbon containing formation,oxygen within the portion may form carbon dioxide. A formation may bechosen and/or conditions in a formation may be adjusted to inhibitproduction of carbon dioxide and other oxides. In an embodiment,production of carbon dioxide may be reduced by selecting and treating aportion of a hydrocarbon containing formation having a vitrinitereflectance of greater than about 0.5%.

[0818] An amount of carbon dioxide that can be produced from a kerogencontaining formation may be dependent on an oxygen content initiallypresent in the formation and/or an atomic oxygen to carbon ratio of thekerogen. In some in situ conversion embodiments, formations to besubjected to in situ conversion may include kerogen with an atomicoxygen weight percentage of less than about 20 weight %, 15 weight %,and/or 10 weight %. In some in situ conversion embodiments, formationsto be subjected to in situ conversion may include kerogen with an atomicoxygen to carbon ratio of less than about 0.15. In some in situconversion embodiments, a formation selected for treatment may have anatomic oxygen to carbon ratio of about 0.03 to about 0.12.

[0819] Heating a hydrocarbon containing formation may include providinga large amount of energy to heat sources located within the formation.Hydrocarbon containing formations may also contain some water. Asignificant portion of energy initially provided to a formation may beused to heat water within the formation. An initial rate of temperatureincrease may be reduced by the presence of water in the formation.Excessive amounts of heat and/or time may be required to heat aformation having a high moisture content to a temperature sufficient topyrolyze hydrocarbons in the formation. In certain embodiments, watermay be inhibited from flowing into a formation subjected to in situconversion. A formation to be subjected to in situ conversion may have alow initial moisture content. The formation may have an initial moisturecontent that is less than about 15 weight %. Some formations that are tobe subjected to in situ conversion may have an initial moisture contentof less than about 10 weight %. Other formations that are to beprocessed using an in situ conversion process may have initial moisturecontents that are greater than about 15 weight %. Formations withinitial moisture contents above about 15 weight % may incur significantenergy costs to remove the water that is initially present in theformation during heating to pyrolysis temperatures.

[0820] A hydrocarbon containing formation may be selected for treatmentbased on additional factors such as, but not limited to, thickness ofhydrocarbon containing layers within the formation, assessed liquidproduction content, location of the formation, and depth of hydrocarboncontaining layers. A hydrocarbon containing formation may includemultiple layers. Such layers may include hydrocarbon containing layers,as well as layers that are hydrocarbon free or have relatively lowamounts of hydrocarbons. Conditions during formation may determine thethickness of hydrocarbon and non-hydrocarbon layers in a hydrocarboncontaining formation. A hydrocarbon containing formation to be subjectedto in situ conversion will typically include at least one hydrocarboncontaining layer having a thickness sufficient for economical productionof formation fluids. Richness of a hydrocarbon containing layer may be afactor used to determine if a formation will be treated by in situconversion. A thin and rich hydrocarbon layer may be able to producesignificantly more valuable hydrocarbons than a much thicker, less richhydrocarbon layer. Producing hydrocarbons from a formation that is boththick and rich is desirable.

[0821] Each hydrocarbon containing layer of a formation may have apotential formation fluid yield or richness. The richness of ahydrocarbon layer may vary in a hydrocarbon layer and between differenthydrocarbon layers in a formation. Richness may depend on many factorsincluding the conditions under which the hydrocarbon containing layerwas formed, an amount of hydrocarbons in the layer, and/or a compositionof hydrocarbons in the layer. Richness of a hydrocarbon layer may beestimated in various ways. For example, richness may be measured by aFischer Assay. The Fischer Assay is a standard method which involvesheating a sample of a hydrocarbon containing layer to approximately 500°C. in one hour, collecting products produced from the heated sample, andquantifying the amount of products produced. A sample of a hydrocarboncontaining layer may be obtained from a hydrocarbon containing formationby a method such as coring or any other sample retrieval method.

[0822] An in situ conversion process may be used to treat formationswith hydrocarbon layers that have thicknesses greater than about 10 m.Thick formations may allow for placement of heat sources so thatsuperposition of heat from the heat sources efficiently heats theformation to a desired temperature. Formations having hydrocarbon layersthat are less than 10 m thick may also be treated using an in situconversion process. In some in situ conversion embodiments of thinhydrocarbon layer formations, heat sources may be inserted in oradjacent to the hydrocarbon layer along a length of the hydrocarbonlayer (e.g., with horizontal or directional drilling). Heat losses tolayers above and below the thin hydrocarbon layer or thin hydrocarbonlayers may be offset by an amount and/or quality of fluid produced fromthe formation.

[0823]FIG. 3 shows a schematic view of an embodiment of a portion of anin situ conversion system for treating a hydrocarbon containingformation. Heat sources 508 may be placed within at least a portion ofthe hydrocarbon containing formation. Heat sources 508 may include, forexample, electric heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 508 mayalso include other types of heaters. Heat sources 508 may provide heatto at least a portion of a hydrocarbon containing formation. Energy maybe supplied to the heat sources 508 through supply lines 510. Supplylines 510 may be structurally different depending on the type of heatsource or heat sources being used to heat the formation. Supply lines510 for heat sources may transmit electricity for electric heaters, maytransport fuel for combustors, or may transport heat exchange fluid thatis circulated within the formation.

[0824] Production wells 512 may be used to remove formation fluid fromthe formation. Formation fluid produced from production wells 512 may betransported through collection piping 514 to treatment facilities 516.Formation fluids may also be produced from heat sources 508. Forexample, fluid may be produced from heat sources 508 to control pressurewithin the formation adjacent to the heat sources. Fluid produced fromheat sources 508 may be transported through tubing or piping tocollection piping 514 or the produced fluid may be transported throughtubing or piping directly to treatment facilities 516. Treatmentfacilities 516 may include separation units, reaction units, upgradingunits, fuel cells, turbines, storage vessels, and other systems andunits for processing produced formation fluids.

[0825] An in situ conversion system for treating hydrocarbons mayinclude barrier wells 518. Barrier wells may be used to form a barrieraround a treatment area. The barrier may inhibit fluid flow into and/orout of the treatment area. Barrier wells may be, but are not limited to,dewatering wells (vacuum wells), capture wells, injection wells, groutwells, or freeze wells. In some embodiments, barrier wells 518 may bedewatering wells. Dewatering wells may remove liquid water and/orinhibit liquid water from entering a portion of a hydrocarbon containingformation to be heated, or to a formation being heated. A plurality ofwater wells may surround all or a portion of a formation to be heated.In the embodiment depicted in FIG. 3, the dewatering wells are shownextending only along one side of heat sources 508, but dewatering wellstypically encircle all heat sources 508 used, or to be used, to heat theformation.

[0826] Dewatering wells may be placed in one or more rings surroundingselected portions of the formation. New dewatering wells may need to beinstalled as an area being treated by the in situ conversion processexpands. An outermost row of dewatering wells may inhibit a significantamount of water from flowing into the portion of formation that isheated or to be heated. Water produced from the outermost row ofdewatering wells should be substantially clean, and may require littleor no treatment before being released. An innermost row of dewateringwells may inhibit water that bypasses the outermost row from flowinginto the portion of formation that is heated or to be heated. Theinnermost row of dewatering wells may also inhibit outward migration ofvapor from a heated portion of the formation into surrounding portionsof the formation. Water produced by the innermost row of dewateringwells may include some hydrocarbons. The water may need to be treatedbefore being released. Alternately, water with hydrocarbons may bestored and used to produce synthesis gas from a portion of the formationduring a synthesis gas phase of the in situ conversion process. Thedewatering wells may reduce heat loss to surrounding portions of theformation, may increase production of vapors from the heated portion,and/or may inhibit contamination of a water table proximate the heatedportion of the formation.

[0827] In some embodiments, pressure differences between successive rowsof dewatering wells may be minimized (e.g., maintained relatively low ornear zero) to create a “no or low flow” boundary between rows.

[0828] In some in situ conversion process embodiments, a fluid may beinjected in the innermost row of wells. The injected fluid may maintaina sufficient pressure around a pyrolysis zone to inhibit migration offluid from the pyrolysis zone through the formation. The fluid may actas an isolation barrier between the outermost wells and the pyrolysisfluids. The fluid may improve the efficiency of the dewatering wells.

[0829] In certain embodiments, wells initially used for one purpose maybe later used for one or more other purposes, thereby lowering projectcosts and/or decreasing the time required to perform certain tasks. Forinstance, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begunand/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.), and monitoring wells may later be used for otherpurposes.

[0830] Hydrocarbons to be subjected to in situ conversion may be locatedunder a large area. The in situ conversion system may be used to treatsmall portions of the formation, and other sections of the formation maybe treated as time progresses. In an embodiment of a system for treatinga formation (e.g., an oil shale formation), a field layout for 24 yearsof development may be divided into 24 individual plots that representindividual drilling years. Each plot may include 120 “tiles” (repeatingmatrix patterns) wherein each plot is made of 6 rows by 20 columns oftiles. Each tile may include 1 production well and 12 or 18 heaterwells. The heater wells may be placed in an equilateral triangle patternwith a well spacing of about 12 m. Production wells may be located incenters of equilateral triangles of heater wells, or the productionwells may be located approximately at a midpoint between two adjacentheater wells.

[0831] In certain embodiments, heat sources will be placed within aheater well formed within a hydrocarbon containing formation. The heaterwell may include an opening through an overburden of the formation. Theheater may extend into or through at least one hydrocarbon containingsection (or hydrocarbon containing layer) of the formation. As shown inFIG. 4, an embodiment of heater well 520 may include an opening inhydrocarbon layer 522 that has a helical or spiral shape. A spiralheater well may increase contact with the formation as opposed to avertically positioned heater. A spiral heater well may provide expansionroom that inhibits buckling or other modes of failure when the heaterwell is heated or cooled. In some embodiments, heater wells may includesubstantially straight sections through overburden 524. Use of astraight section of heater well through the overburden may decrease heatloss to the overburden and reduce the cost of the heater well.

[0832] As shown in FIG. 5, a heat source embodiment may be placed intoheater well 520. Heater well 520 may be substantially “U” shaped. Thelegs of the “U” may be wider or more narrow depending on the particularheater well and formation characteristics. First portion 526 and thirdportion 528 of heater well 520 may be arranged substantiallyperpendicular to an upper surface of hydrocarbon layer 522 in someembodiments. In addition, the first and the third portion of the heaterwell may extend substantially vertically through overburden 524. Secondportion 530 of heater well 520 may be substantially parallel to theupper surface of the hydrocarbon layer.

[0833] Multiple heat sources (e.g., 2, 3, 4, 5, 10 heat sources or more)may extend from a heater well in some situations. As shown in FIG. 6,heat sources 508A, 508B, and 508C extend through overburden 524 intohydrocarbon layer 522 from heater well 520. Multiple wells extendingfrom a single wellbore may be used when surface considerations (e.g.,aesthetics, surface land use concerns, and/or unfavorable soilconditions near the surface) make it desirable to concentrate wellplatforms in a small area. For example, in areas where the soil isfrozen and/or marshy, it may be more cost-effective to have a minimalnumber of well platforms located at selected sites.

[0834] In certain embodiments, a first portion of a heater well mayextend from the ground surface, through an overburden, and into ahydrocarbon containing formation. A second portion of the heater wellmay include one or more heater wells in the hydrocarbon containingformation. The one or more heater wells may be disposed within thehydrocarbon containing formation at various angles. In some embodiments,at least one of the heater wells may be disposed substantially parallelto a boundary of the hydrocarbon containing formation. In someembodiments, at least one of the heater wells may be substantiallyperpendicular to the hydrocarbon containing formation. In addition, oneof the one or more heater wells may be positioned at an angle betweenperpendicular and parallel to a layer in the formation.

[0835]FIG. 7 illustrates a schematic of view of multilateral or sidetracked lateral heaters branched from a single well in a hydrocarboncontaining formation. In relatively thin and deep layers found in ahydrocarbon containing formation (e.g., in a coal, oil shale, or tarsands formation), it may be advantageous to place more than one heatersubstantially horizontally within the relatively thin layer ofhydrocarbons. For example, an oil shale layer may have a richnessgreater than about 0.06 L/kg and a relatively low initial thermalconductivity. Heat provided to a thin layer with a low thermalconductivity from a horizontal wellbore may be more effectively trappedwithin the thin layer and reduce heat losses from the layer.Substantially vertical opening 532 may be placed in hydrocarbon layer522. Substantially vertical opening 532 may be an elongated portion ofan opening formed in hydrocarbon layer 522. Hydrocarbon layer 522 may bebelow overburden 524.

[0836] One or more substantially horizontal openings 534 may also beplaced in hydrocarbon layer 522. Horizontal openings 534 may, in someembodiments, contain perforated liners. The horizontal openings 534 maybe coupled to vertical opening 532. Horizontal openings 534 may beelongated portions that diverge from the elongated portion of verticalopening 532. Horizontal openings 534 may be formed in hydrocarbon layer522 after vertical opening 532 has been formed. In certain embodiments,openings 534 may be angled upwards to facilitate flow of formationfluids towards the production conduit.

[0837] Each horizontal opening 534 may lie above or below an adjacenthorizontal opening. In an embodiment, six horizontal openings 534 may beformed in hydrocarbon layer 522. Three horizontal openings 534 may face180°, or in a substantially opposite direction, from three additionalhorizontal openings 534. Two horizontal openings facing substantiallyopposite directions may lie in a substantially identical vertical planewithin the formation. Any number of horizontal openings 534 may becoupled to a single vertical opening 532, depending on, but not limitedto, a thickness of hydrocarbon layer 522, a type of formation, a desiredheating rate in the formation, and a desired production rate.

[0838] Production conduit 536 may be placed substantially verticallywithin vertical opening 532. Production conduit 536 may be substantiallycentered within vertical opening 532. Pump 538 may be coupled toproduction conduit 536. Such a pump may be used, in some embodiments, topump formation fluids from the bottom of the well. Pump 538 may be a rodpump, progressing cavity pump (PCP), centrifugal pump, jet pump, gaslift pump, submersible pump, rotary pump, etc.

[0839] One or more heaters 540 may be placed within each horizontalopening 534. Heaters 540 may be placed in hydrocarbon layer 522 throughvertical opening 532 and into horizontal opening 534.

[0840] In some embodiments, heater 540 may be used to generate heatalong a length of the heater within vertical opening 532 and horizontalopening 534. In other embodiments, heater 540 may be used to generateheat only within horizontal opening 534. In certain embodiments, heatgenerated by heater 540 may be varied along its length and/or variedbetween vertical opening 532 and horizontal opening 534. For example,less heat may be generated by heater 540 in vertical opening 532 andmore heat may be generated by the heater in horizontal opening 534. Itmay be advantageous to have at least some heating within verticalopening 532. This may maintain fluids produced from the formation in avapor phase in production conduit 536 and/or may upgrade the producedfluids within the production well. Having production conduit 536 andheaters 540 installed into a formation through a single opening in theformation may reduce costs associated with forming openings in theformation and installing production equipment and heaters within theformation.

[0841]FIG. 8 depicts a schematic view from an elevated position of theembodiment of FIG. 7. One or more vertical openings 532 may be formed inhydrocarbon layer 522. Each of vertical openings 532 may lie along asingle plane in hydrocarbon layer 522. Horizontal openings 534 mayextend in a plane substantially perpendicular to the plane of verticalopenings 532. Additional horizontal openings 534 may lie in a planebelow the horizontal openings as shown in the schematic depiction ofFIG. 7. A number of vertical openings 532 and/or a spacing betweenvertical openings 532 may be determined by, for example, a desiredheating rate or a desired production rate. In some embodiments, spacingbetween vertical openings may be about 4 m to about 30 m. Longer orshorter spacings may be used to meet specific formation needs. A lengthof a horizontal opening 534 may be up to about 1600 m. However, a lengthof horizontal openings 534 may vary depending on, for example, a maximuminstallation cost, an area of hydrocarbon layer 522, or a maximumproducible heater length.

[0842] In an in situ conversion process embodiment, a formation havingone or more thin hydrocarbon layers may be treated. The hydrocarbonlayer may be, but is not limited to, a rich, thin coal seam; a rich,thin oil shale; or a relatively thin hydrocarbon layer in a tar sandsformation. In some in situ conversion process embodiments, suchformations may be treated with heat sources that are positionedsubstantially horizontal within and/or adjacent to the thin hydrocarbonlayer or thin hydrocarbon layers. A relatively thin hydrocarbon layermay be at a substantial depth below a ground surface. For example, aformation may have an overburden of up to about 650 m in depth. The costof drilling a large number of substantially vertical wells within aformation to a significant depth may be expensive. It may beadvantageous to place heaters horizontally within these formations toheat large portions of the formation for lengths up to about 1600 m.Using horizontal heaters may reduce the number of vertical wells thatare needed to place a sufficient number of heaters within the formation.

[0843]FIG. 9 illustrates an embodiment of hydrocarbon containing layer522 that may be at a near-horizontal angle with respect to surface 542of the ground. An angle of hydrocarbon containing layer 522, however,may vary. For example, hydrocarbon containing layer 522 may dip or besteeply dipping. Economically viable production of a steeply dippinghydrocarbon containing layer may not be possible using presentlyavailable mining methods.

[0844] A dipping or relatively steeply dipping hydrocarbon containinglayer may be subjected to an in situ conversion process. For example, aset of production wells may be disposed near a highest portion of adipping hydrocarbon layer of a hydrocarbon containing formation.Hydrocarbon portions adjacent to and below the production wells may beheated to pyrolysis temperatures. Pyrolysis fluid may be produced fromthe production wells. As production from the top portion declines,deeper portions of the formation may be heated to pyrolysistemperatures. Vapors may be produced from the hydrocarbon containinglayer by transporting vapor through the previously pyrolyzedhydrocarbons. High permeability resulting from pyrolysis and productionof fluid from the upper portion of the formation may allow for vaporphase transport with minimal pressure loss. Vapor phase transport offluids produced in the formation may eliminate a need to have deepproduction wells in addition to the set of production wells. A number ofproduction wells required to process the formation may be reduced.Reducing the number of production wells required for production mayincrease economic viability of an in situ conversion process.

[0845] In steeply dipping formations, directional drilling may be usedto form an opening in the formation for a heater well or productionwell. Directional drilling may include drilling an opening in which theroute/course of the opening may be planned before drilling. Such anopening may usually be drilled with rotary equipment. In directionaldrilling, a route/course of an opening may be controlled by deflectionwedges, etc.

[0846] A wellbore may be formed using a drill equipped with a steerablemotor and an accelerometer. The steerable motor and accelerometer mayallow the wellbore to follow a layer in the hydrocarbon containingformation. A steerable motor may maintain a substantially constantdistance between heater well 520 and a boundary of hydrocarboncontaining layer 522 throughout drilling of the opening.

[0847] In some in situ conversion embodiments, geosteered drilling maybe used to drill a wellbore in a hydrocarbon containing formation.Geosteered drilling may include determining or estimating a distancefrom an edge of hydrocarbon containing layer 522 to the wellbore with asensor. The sensor may monitor variations in characteristics or signalsin the formation. The characteristic or signal variance may allow fordetermination of a desired drill path. The sensor may monitorresistance, acoustic signals, magnetic signals, gamma rays, and/or othersignals within the formation. A drilling apparatus for geosteereddrilling may include a steerable motor. The steerable motor may becontrolled to maintain a predetermined distance from an edge of ahydrocarbon containing layer based on data collected by the sensor.

[0848] In some in situ conversion embodiments, wellbores may be formedin a formation using other techniques. Wellbores may be formed byimpaction techniques and/or by sonic drilling techniques. The methodused to form wellbores may be-determined based on a number of factors.The factors may include, but are not limited to, accessibility of thesite, depth of the wellbore, properties of the overburden, andproperties of the hydrocarbon containing layer or layers.

[0849]FIG. 10 illustrates an embodiment of a plurality of heater wells520 formed in hydrocarbon containing layer 522. Hydrocarbon containinglayer 522 may be a steeply dipping layer. Heater wells 520 may be formedin the: formation such that two or more of the heater wells aresubstantially parallel to each other, and/or such that at least oneheater well is substantially parallel to a boundary of hydrocarboncontaining layer 522. For example, one or more of heater wells 520 maybe formed in hydrocarbon containing layer 522 by a magnetic steeringmethod.

[0850] Magnetic steering may include drilling heater well 520 parallelto an adjacent heater well. The adjacent well may have been previouslydrilled. Magnetic steering may include directing the drilling by sensingand/or determining a magnetic field produced in an adjacent heater well.For example, the magnetic field may be produced in the adjacent heaterwell by permanent magnets positioned in the adjacent heater well, byflowing a current through the casing of the adjacent heater well, and/orby flowing a current through an insulated current-carrying wirelinedisposed in the adjacent heater well.

[0851] In some embodiments, heated portion 590 may extend radially fromheat source 508, as shown in FIG. 11. For example, a width of heatedportion 590, in a direction extending radially from heat source 508, maybe about 0 m to about 10 m. A width of heated portion 590 may vary,however, depending upon, for example, heat provided by heat source 508and the characteristics of the formation. Heat provided by heat source508 will typically transfer through the heated portion to create atemperature gradient within the heated portion. For example, atemperature proximate the heater well will generally be higher than atemperature proximate an outer lateral boundary of the heated portion. Atemperature gradient within the heated portion may vary within theheated portion depending on various factors (e.g., thermal conductivityof the formation, density, and porosity).

[0852] As heat transfers through heated portion 590 of the hydrocarboncontaining formation, a temperature within at least a section of theheated portion may be within a pyrolysis temperature range. As the heattransfers away from the heat source, a front at which pyrolysis occurswill in many instances travel outward from the heat source. For example,heat from the heat source may be allowed to transfer into a selectedsection of the heated portion such that heat from the heat sourcepyrolyzes at least some of the hydrocarbons within the selected section.Pyrolysis may occur within selected section 592 of the heated portion,and pyrolyzation fluids will be generated in the selected section.

[0853] Selected section 592 may have a width radially extending from theinner lateral boundary of the selected section. For a single heat sourceas depicted in FIG. 11, width of the selected section may be dependenton a number of factors. The factors may include, but are not limited to,time that heat source 508 is supplying energy to the formation, thermalconductivity properties of the formation, extent of pyrolyzation ofhydrocarbons in the formation. A width of selected section 592 mayexpand for a significant time after initialization of heat source 508. Awidth of selected section 592 may initially be zero and may expand to 10m or more after initialization of heat source 508.

[0854] An inner boundary of selected section 592 may be radially spacedfrom the heat source. The inner boundary may define a volume of spenthydrocarbons 594. Spent hydrocarbons 594 may include a volume ofhydrocarbon material that is transformed to coke due to the proximityand heat of heat source 508. Coking may occur by pyrolysis reactionsthat occur due to a rapid increase in temperature in a short timeperiod. Applying heat to a formation at a controlled rate may allow foravoidance of significant coking, however, some coking may occur in thevicinity of heat sources. Spent hydrocarbons 594 may also include avolume of material that has been subjected to pyrolysis and the removalof pyrolysis fluids. The volume of material that has been subjected topyrolysis and the removal of pyrolysis fluids may produce insignificantamounts or no additional pyrolysis fluids with increases in temperature.The inner lateral boundary may advance radially outwards as timeprogresses during operation of an in situ conversion process.

[0855] In some embodiments, a plurality of heated portions may existwithin a unit of heat sources. A unit of heat sources refers to aminimal number of heat sources that form a template that is repeated tocreate a pattern of heat sources within the formation. The heat sourcesmay be located within the formation such that superposition(overlapping) of heat produced from the heat sources occurs. Forexample, as illustrated in FIG. 12, transfer of heat from two or moreheat sources 508 results in superposition of heat to region 596 betweenthe heat sources 508. Superposition of heat may occur between two,three, four, five, six, or more heat sources. Region 596 is an area inwhich temperature is influenced by various heat sources. Superpositionof heat may provide the ability to efficiently raise the temperature oflarge volumes of a formation to pyrolysis temperatures. The size ofregion 596 may be significantly affected by the spacing between heatsources.

[0856] Superposition of heat may increase a temperature in at least aportion of the formation to a temperature sufficient for pyrolysis ofhydrocarbons within the portion. Superposition of heat to region 596 mayincrease the quantity of hydrocarbons in a formation that are subjectedto pyrolysis. Selected sections of a formation that are subjected topyrolysis may include regions 598 brought into a pyrolysis temperaturerange by heat transfer from substantially only one heat source. Selectedsections of a formation that are subjected to pyrolysis may also includeregions 596 brought into a pyrolysis temperature range by superpositionof heat from multiple heat sources.

[0857] A pattern of heat sources will often include many units of heatsources. There will typically be many heated portions, as well as manyselected sections within the pattern of heat sources. Superposition ofheat within a pattern of heat sources may decrease the time necessary toreach pyrolysis temperatures within the multitude of heated portions.Superposition of heat may allow for a relatively large spacing betweenadjacent heat sources. In some embodiments, a large spacing may providefor a relatively slow heating rate of hydrocarbon material. The slowheating rate may allow for pyrolysis of hydrocarbon material withminimal coking or no coking within the formation away from areas in thevicinity of the heat sources. Heating from heat sources allows theselected section to reach pyrolysis temperatures so that allhydrocarbons within the selected section may be subject to pyrolysisreactions. In some in situ conversion embodiments, a majority ofpyrolysis fluids are produced when the selected section is within arange from about 0 m to about 25 m from a heat source.

[0858] In an in situ conversion process embodiment, a heating rate maybe controlled to minimize costs associated with heating a selectedsection. The costs may include, for example, input energy costs andequipment costs. In certain embodiments, a cost associated with heatinga selected section may be minimized by reducing a heating rate when thecost associated with heating is relatively high and increasing theheating rate when the cost associated with heating is relatively low.For example, a heating rate of about 330 watts/m may be used when theassociated cost is relatively high, and a heating rate of about 1640watts/m may be used when the associated cost is relatively low. Incertain embodiments, heating rates may be varied between about 300watts/m and about 800 watts/m when the associated cost is relativelyhigh and between about 1000 watts/m and 1800 watts/m when the associatedcost is relatively low. The cost associated with heating may berelatively high at peak times of energy use, such as during the daytime.For example, energy use may be high in warm climates during the daytimein the summer due to energy use for air conditioning. Low times ofenergy use may be, for example, at night or during weekends, when energydemand tends to be lower. In an embodiment, the heating rate may bevaried from a higher heating rate during low energy usage times, such asduring the night, to a lower heating rate during high energy usagetimes, such as during the day.

[0859] As shown in FIG. 3, in addition to heat sources 508, one or moreproduction wells 512 will typically be placed within the portion of thehydrocarbon containing formation. Formation fluids may be producedthrough production well 512. In some embodiments, production well 512may include a heat source. The heat source may heat the portions of theformation at or near the production well and allow for vapor phaseremoval of formation fluids. The need for high temperature pumping ofliquids from the production well may be reduced or eliminated. Avoidingor limiting high temperature pumping of liquids may significantlydecrease production costs. Providing heating at or through theproduction well may: (1) inhibit condensation and/or refluxing ofproduction fluid when such production fluid is moving in the productionwell proximate the overburden, (2) increase heat input into theformation, and/or (3) increase formation permeability at or proximatethe production well. In some in situ conversion process embodiments, anamount of heat supplied to production wells is significantly less thanan amount of heat applied to heat sources that heat the formation.

[0860] Because permeability and/or porosity increases in the heatedformation, produced vapors may flow considerable distances through theformation with relatively little pressure differential. Increases inpermeability may result from a reduction of mass of the heated portiondue to vaporization of water, removal of hydrocarbons, and/or creationof fractures. Fluids may flow more easily through the heated portion. Insome embodiments, production wells may be provided in upper portions ofhydrocarbon layers. As shown in FIG. 9, production wells 512 may extendinto a hydrocarbon containing formation near the top of heated portion590. Extending production wells significantly into the depth of theheated hydrocarbon layer may be unnecessary.

[0861] Fluid generated within a hydrocarbon containing formation maymove a considerable distance through the hydrocarbon containingformation as a vapor. The considerable distance may be over 1000 mdepending on various factors (e.g., permeability of the formation,properties of the fluid, temperature of the formation, and pressuregradient allowing movement of the fluid). Due to increased permeabilityin formations subjected to in situ conversion and formation fluidremoval, production wells may only need to be provided in every otherunit of heat sources or every third, fourth, fifth, or sixth units ofheat sources.

[0862] Embodiments of a production well may include valves that alter,maintain, and/or control a pressure of at least a portion of theformation. Production wells may be cased wells. Production wells mayhave production screens or perforated casings adjacent to productionzones. In addition, the production wells may be surrounded by sand,gravel or other packing materials adjacent to production zones.Production wells 512 may be coupled to treatment facilities 516, asshown in FIG. 3.

[0863] During an in situ process, production wells may be operated suchthat the production wells are at a lower pressure than other portions ofthe formation. In some embodiments, a vacuum may be drawn at theproduction wells. Maintaining the production wells at lower pressuresmay inhibit fluids in the formation from migrating outside of the insitu treatment area.

[0864]FIG. 13 illustrates an embodiment of production well 512 placed inhydrocarbon layer 522. Production well 512 may be used to produceformation fluids from hydrocarbon layer 522. Hydrocarbon layer 522 maybe treated using an in situ conversion process. Production conduit 536may be placed within production well 512. In an embodiment, productionconduit 536 is a hollow sucker rod placed in production well 512.Production well 512 may have a casing, or lining, placed along thelength of the production well. The casing may have openings, orperforations, to allow formation fluids to enter production well 512.Formation fluids may include vapors and/or liquids. Production conduit536 and production well 512 may include non-corrosive materials such assteel.

[0865] In certain embodiments, production conduit 536 may include heatsource 508. Heat source 508 may be a heater placed inside or outsideproduction conduit 536 or formed as part of the production conduit. Heatsource 508 may be a heater such as an insulated conductor heater, aconductor-in-conduit heater, or a skin-effect heater. A skin-effectheater is an electric heater that uses eddy current heating to induceresistive losses in production conduit 536 to heat the productionconduit. An example of a skin-effect heater is obtainable from DagangOil Products (China).

[0866] Heating of production conduit 536 may inhibit condensation and/orrefluxing in the production conduit or within production well 512. Incertain embodiments, heating of production conduit 536 may inhibitplugging of pump 538 by liquids (e.g., heavy hydrocarbons). For example,heat source 508 may heat production conduit 536 to about 35° C. tomaintain the mobility of liquids in the production conduit to inhibitplugging of pump 538 or the production conduit. In certain embodiments(e.g., for formations greater than about 100 m in depth), heat source508 may heat production conduit 536 and/or production well 512 totemperatures of about 200° C. to about 250° C. to maintain producedfluids substantially in a vapor phase by inhibiting condensation and/orreflux of fluids in the production well.

[0867] Pump 538 may be coupled to production conduit 536. Pump 538 maybe used to pump formation fluids from hydrocarbon layer 522 intoproduction conduit 536. Pump 538 may be any pump used to pump fluids,such as a rod pump, PCP, jet pump, gas lift pump, centrifugal pump,rotary pump, or submersible pump. Pump 538 may be used to pump fluidsthrough production conduit 536 to a surface of the formation aboveoverburden 524.

[0868] In certain embodiments, pump 538 can be used to pump formationfluids that may be liquids. Liquids may be produced from hydrocarbonlayer 522 prior to production well 512 being heated to a temperaturesufficient to vaporize liquids within the production well. In someembodiments, liquids produced from the formation tend to include water.Removing liquids from the formation before heating the formation, orduring early times of heating before pyrolysis occurs, tends to reducethe amount of heat input that is needed to produce hydrocarbons from theformation.

[0869] In an embodiment, formation fluids that are liquids may beproduced through production conduit 536 using pump 538. Formation fluidsthat are vapors may be simultaneously produced through an annulus ofproduction well 512 outside of production conduit 536.

[0870] Insulation may be placed on a wall of production well 512 in asection of the production well within overburden 524. The insulation maybe cement or any other suitable low heat transfer material. Insulatingthe overburden section of production well 512 may inhibit transfer ofheat from fluids being produced from the formation into the overburden.

[0871] In an in situ conversion process embodiment, a mixture may beproduced from a hydrocarbon containing formation. The mixture may beproduced through a heater well disposed in the formation. Producing themixture through the heater well may increase a production rate of themixture as compared to a production rate of a mixture produced through anon-heater well. A non-heater well may include a production well. Insome embodiments, a production well may be heated to increase aproduction rate.

[0872] A heated production well may inhibit condensation of highercarbon numbers (C₅ or above) in the production well. A heated productionwell may inhibit problems associated with producing a hot, multi-phasefluid from a formation.

[0873] A heated production well may have an improved production rate ascompared to a non-heated production well. Heat applied to the formationadjacent to the production well from the production well may increaseformation permeability adjacent to the production well by vaporizing andremoving liquid phase fluid adjacent to the production well and/or byincreasing the permeability of the formation adjacent to the productionwell by formation of macro and/or micro fractures. A heater in a lowerportion of a production well may be turned off when superposition ofheat from heat sources heats the formation sufficiently to counteractbenefits provided by heating from within the production well. In someembodiments, a heater in an upper portion of a production well mayremain on after a heater in a lower portion of the well is deactivated.The heater in the upper portion of the well may inhibit condensation andreflux of formation fluid.

[0874] In some embodiments, heated production wells may improve productquality by causing production through a hot zone in the formationadjacent to the heated production well. A final phase of thermalcracking may exist in the hot zone adjacent to the production well.Producing through a hot zone adjacent to a heated production well mayallow for an increased olefin content in non-condensable hydrocarbonsand/or condensable hydrocarbons in the formation fluids. The hot zonemay produce formation fluids with a greater percentage ofnon-condensable hydrocarbons due to thermal cracking in the hot zone.The extent of thermal cracking may depend on a temperature of the hotzone and/or on a residence time in the hot zone. A heater can bedeliberately run hotter to promote the further in situ upgrading ofhydrocarbons. This may be an advantage in the case of heavy hydrocarbons(e.g., bitumen or tar) in relatively permeable formations, in which someheavy hydrocarbons tend to flow into the production well beforesufficient upgrading has occurred.

[0875] In an embodiment, heating in or proximate a production well maybe controlled such that a desired mixture is produced through theproduction well. The desired mixture may have a selected yield ofnon-condensable hydrocarbons. For example, the selected yield ofnon-condensable hydrocarbons may be about 75 weight % non-condensablehydrocarbons or, in some embodiments, about 50 weight % to about 100weight %. In other embodiments, the desired mixture may have a selectedyield of condensable hydrocarbons. The selected yield of condensablehydrocarbons may be about 75 weight % condensable hydrocarbons or, insome embodiments, about 50 weight % to about 95 weight %.

[0876] A temperature and a pressure may be controlled within theformation to inhibit the production of carbon dioxide and increaseproduction of carbon monoxide and molecular hydrogen during synthesisgas production. In an embodiment, the mixture is produced through aproduction well (or heater well), which may be heated to inhibit theproduction of carbon dioxide. In some embodiments, a mixture producedfrom a first portion of the formation may be recycled into a secondportion of the formation to inhibit the production of carbon dioxide.The mixture produced from the first portion may be at a lowertemperature than the mixture produced from the second portion of theformation.

[0877] A desired volume ratio of molecular hydrogen to carbon monoxidein synthesis gas may be produced from the formation. The desired volumeratio may be about 2.0:1. In an embodiment, the volume ratio may bemaintained between about 1.8:1 and 2.2:1 for synthesis gas.

[0878]FIG. 14 illustrates a pattern of heat sources 508 and productionwells 512 that may be used to treat a hydrocarbon containing formation.Heat sources 508 may be arranged in a unit of heat sources such astriangular pattern 600. Heat sources 508, however, may be arranged in avariety of patterns including, but not limited to, squares, hexagons,and other polygons. The pattern may include a regular polygon to promoteuniform heating of the formation in which the heat sources are placed.The pattern may also be a line drive pattern. A line drive patterngenerally includes a first linear array of heater wells, a second lineararray of heater wells, and a production well or a linear array ofproduction wells between the first and second linear array of heaterwells.

[0879] A distance from a node of a polygon to a centroid of the polygonis smallest for a 3-sided polygon and increases with increasing numberof sides of the polygon. The distance from a node to the centroid for anequilateral triangle is (length/2)/(square root(3)/2) or 0.5774 timesthe length. For a square, the distance from a node to the centroid is(length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon,the distance from a node to the centroid is (length/2)/(1/2) or thelength. The difference in distance between a heat source and a midpointto a second heat source (length/2) and the distance from a heat sourceto the centroid for an equilateral pattern (0.5774 times the length) issignificantly less for the equilateral triangle pattern than for anyhigher order polygon pattern. The small difference means thatsuperposition of heat may develop more rapidly and that the formationmay rise to a more uniform temperature between heat sources using anequilateral triangle pattern rather than a higher order polygon pattern.

[0880] Triangular patterns tend to provide-more uniform heating to aportion of the formation in comparison to other patterns such as squaresand/or hexagons. Triangular patterns tend to provide faster heating to apredetermined temperature in comparison to other patterns such assquares or hexagons. The use of triangular patterns may result insmaller volumes of a formation being overheated. A plurality of units ofheat sources such as triangular pattern 600 may be arrangedsubstantially adjacent to each other to form a repetitive pattern ofunits over an area of the formation. For example, triangular patterns600 may be arranged substantially adjacent to each other in a repetitivepattern of units by inverting an orientation of adjacent triangles 600.Other patterns of heat sources 508 may also be arranged such thatsmaller patterns may be disposed adjacent to each other to form largerpatterns.

[0881] Production wells may be disposed in the formation in a repetitivepattern of units. In certain embodiments, production well 512 may bedisposed proximate a center of every third triangle 600 arranged in thepattern. Production well 512, however, may be disposed in every triangle600 or within just a few triangles. In some embodiments, a productionwell may be placed within every 13, 20, or 30 heater well triangles. Forexample, a ratio of heat sources in the repetitive pattern of units toproduction wells in the repetitive pattern of units may be more thanapproximately 5 (e.g., more than 6, 7, 8, or 9). In some well patternembodiments, three or more production wells may be located within anarea defined by a repetitive pattern of units. For example, productionwells 602 may be located within an area defined by repetitive pattern ofunits 604. Production wells 602 may be located in the formation in aunit of production wells. The location of production wells 512, 602within a pattern of heat sources 508 may be determined by, for example,a desired heating rate of the hydrocarbon containing formation, aheating rate of the heat sources, the type of heat sources used, thetype of hydrocarbon containing formation (and its thickness), thecomposition of the hydrocarbon containing formation, permeability of theformation, the desired composition to be produced from the formation,and/or a desired production rate.

[0882] One or more injection wells may be disposed within a repetitivepattern of units. For example, injection wells 606 may be located withinan area defined by repetitive pattern of units 608. Injection wells 606may also be located in the formation in a unit of injection wells. Forexample, the unit of injection wells may be a triangular pattern.Injection wells 606, however, may be disposed in any other pattern. Incertain embodiments, one or more production wells and one or moreinjection wells may be disposed in a repetitive pattern of units. Forexample, production wells 610 and injection wells 612 may be locatedwithin an area defined by repetitive pattern of units 614. Productionwells 610 may be located in the formation in a unit of production wells,which may be arranged in a first triangular pattern. In addition,injection wells 612 may be located within the formation in a unit ofproduction wells, which are arranged in a second triangular pattern. Thefirst triangular pattern may be different than the second triangularpattern. For example, areas defined by the first and second triangularpatterns may be different.

[0883] One or more monitoring wells may be disposed within a repetitivepattern of units. Monitoring wells may include one or more devices thatmeasure temperature, pressure, and/or fluid properties. In someembodiments, logging tools may be placed in monitoring well wellbores tomeasure properties within a formation. The logging tools may be moved toother monitoring well wellbores as needed. The monitoring well wellboresmay be cased or uncased wellbores. Monitoring wells 616 may be locatedwithin an area defined by repetitive pattern of units 618. Monitoringwells 616 may be located in the formation in a unit of monitoring wells,which may be arranged in a triangular pattern. Monitoring wells 616,however, may be disposed in any of the other patterns within repetitive,pattern of units 618.

[0884] It is to be understood that a geometrical pattern of heat sources508 and production wells 512 is described herein by example. A patternof heat sources and production wells will in many instances varydepending on, for example, the type of hydrocarbon containing formationto be treated. For example, for relatively thin layers, heater wells maybe aligned along one or more layers along strike or along dip. Forrelatively thick layers, heat sources may be at an angle to one or morelayers (e.g., orthogonally or diagonally).

[0885] A triangular pattern of heat sources may treat a hydrocarbonlayer having a thickness of about 10 m or more. For a thin hydrocarbonlayer (e.g., about 10 m thick or less) a line and/or staggered linepattern of heat sources may treat the hydrocarbon layer.

[0886] For certain thin layers, heating wells may be placed close to anedge of the layer (e.g., in a staggered line instead of a line placed inthe center of the layer) to increase the amount of hydrocarbons producedper unit of energy input. A portion of input heating energy may heatnon-hydrocarbon portions of the formation, but the staggered pattern mayallow superposition of heat to heat a majority of the hydrocarbon layersto pyrolysis temperatures. If the thin formation is heated by placingone or more heater wells in the layer along a center of the thickness, asignificant portion of the hydrocarbon layers may not be heated topyrolysis temperatures. In some embodiments, placing heater wells closerto an edge of the layer may increase the volume of layer undergoingpyrolysis per unit of energy input.

[0887] Exact placement of heater wells, production wells, etc. willdepend on variables specific to the formation (e.g., thickness of thelayer or composition of the layer), project economics, etc. In certainembodiments, heater wells may be substantially horizontal whileproduction wells may be vertical, or vice versa. In some embodiments,wells may be aligned along dip or strike or oriented at an angle betweendip and strike.

[0888] The spacing between heat sources may vary depending on a numberof factors. The factors may include, but are not limited to, the type ofa hydrocarbon containing formation, the selected heating rate, and/orthe selected average temperature to be obtained within the heatedportion. In some well pattern embodiments, the spacing between heatsources may be within a range of about 5 m to about 25 m. In some wellpattern embodiments, spacing between heat sources may be within a rangeof about 8 m to about 15 m.

[0889] The spacing between heat sources may influence the composition offluids produced from a hydrocarbon containing formation. In anembodiment, a computer-implemented simulation may be used to determineoptimum heat source spacings within a hydrocarbon containing formation.At least one property of a portion of hydrocarbon containing formationcan usually be measured. The measured property may include, but is notlimited to, vitrinite reflectance, hydrogen content, atomic hydrogen tocarbon ratio, oxygen content, atomic oxygen to carbon ratio, watercontent, thickness of the hydrocarbon containing formation, and/or theamount of stratification of the hydrocarbon containing formation intoseparate layers of rock and hydrocarbons.

[0890] In certain embodiments, a computer-implemented simulation mayinclude providing at least one measured property to a computer system.One or more sets of heat source spacings in the formation may also beprovided to the computer system. For example, a spacing between heatsources may be less than about 30 m. Alternatively, a spacing betweenheat sources may be less than about 15 m. The simulation may includedetermining properties of fluids produced from the portion as a functionof time for each set of heat source spacings. The produced fluids mayinclude formation fluids such as pyrolyzation fluids or synthesis gas.The determined properties may include, but are not limited to, APIgravity, carbon number distribution, olefin content, hydrogen content,carbon monoxide content, and/or carbon dioxide content. The determinedset of properties of the produced fluid may be compared to a set ofselected properties of a produced fluid. Sets of properties that matchthe set of selected properties may be determined. Furthermore, heatsource spacings may be matched to heat source spacings associated withdesired properties.

[0891] As shown in FIG. 14, unit cell 620 will often include a number ofheat sources 508 disposed within a formation around each production well512. An area of unit cell 620 may be determined by midlines 622 that maybe equidistant and perpendicular to a line connecting two productionwells 512. Vertices 624 of the unit cell may be at the intersection oftwo midlines 622 between production wells 512. Heat sources 508 may bedisposed in any arrangement within the area of unit cell 620. Forexample, heat sources 508 may be located within the formation such thata distance between each heat source varies by less than approximately10%, 20%, or 30%. In addition, heat sources 508 may be disposed suchthat an approximately equal space exists between each of the heatsources. Other arrangements of heat sources 508 within unit cell 620 maybe used. A ratio of heat sources 508 to production wells 512 may bedetermined by counting the number of heat sources 508 and productionwells 512 within unit cell 620 or over the total field.

[0892]FIG. 15 illustrates an embodiment of unit cell 620. Unit cell 620includes heat sources 508D, 508E and production well 512. Unit cell 620may have six full heat sources 508D and six partial heat sources 508E.Full heat sources 508D may be closer to production well 512 than partialheat sources 508E. In addition, an entirety of each of full heat sources508D may be located within unit cell 620. Partial heat sources 508E maybe partially disposed within unit cell 620. Only a portion of heatsource 508E disposed within unit cell 620 may provide heat to a portionof a hydrocarbon containing formation disposed within unit cell 620. Aremaining portion of heat source 508E disposed outside of unit cell 620may provide heat to a remaining portion of the hydrocarbon containingformation outside of unit cell 620. To determine a number of heatsources within unit cell 620, partial heat source 508E may be counted asone-half of full heat source 508D. In other unit cell embodiments,fractions other than ½ (e.g., ⅓) may more accurately describe the amountof heat applied to a portion from a partial heat source based ongeometrical considerations.

[0893] The total number of heat sources in unit cell 620 may include sixfull heat sources 508D that are each counted as one heat source, and sixpartial heat sources 508E that are each counted as one-half of a heatsource. Therefore, a ratio of heat sources 508D, 508E to productionwells 512 in unit cell 620 may be determined as 9:1. A ratio of heatsources to production wells may be varied, however, depending on, forexample, the desired heating rate of the hydrocarbon containingformation, the heating rate of the heat sources, the type of heatsource, the type of hydrocarbon containing formation, the composition ofhydrocarbon containing formation, the desired composition of theproduced fluid, and/or the desired production rate. Providing more heatsource wells per unit area will allow faster heating of the selectedportion and thus hasten the onset of production. However, adding moreheat sources will generally cost more money in installation andequipment. An appropriate ratio of heat sources to production wells mayinclude ratios greater than about 5:1. In some embodiments, anappropriate ratio of heat sources to production wells may be about 10:1,20:1, 50:1, or greater. If larger ratios are used, then project coststend to decrease since less production wells and accompanying equipmentare needed.

[0894] In some embodiments, a selected section is the volume offormation that is within a perimeter defined by the location of theoutermost heat sources (assuming that the formation is viewed fromabove). For example, if four heat sources were located in a singlesquare pattern with an area of about 100 m² (with each source located ata comer of the square), and if the formation had an average thickness ofapproximately 5 m across this area, then the selected section would be avolume of about 500 m³ (i.e., the area multiplied by the averageformation thickness across the area). In many commercial applications,many heat sources (e.g., hundreds or thousands) may be adjacent to eachother to heat a selected section, and therefore only the outermost heatsources (i.e., edge heat sources) would define the perimeter of theselected section.

[0895]FIG. 16 illustrates computational system 626 suitable forimplementing various embodiments of a system and method for in situprocessing of a formation. Computational system 626 typically includescomponents such as one or more central processing units (CPU) 628 withassociated memory mediums, represented by floppy disks 630 or compactdiscs (CDs). The memory mediums may store program instructions forcomputer programs, wherein the program instructions are executable byCPU 628. Computational system 626 may further include one or moredisplay devices such as monitor 632, one or more, alphanumeric inputdevices such as keyboard 634, and/or one or more directional inputdevices such as mouse 636. Computational system 626 is operable toexecute the computer programs to implement (e.g., control, design,simulate, and/or operate) in situ processing of formation systems andmethods.

[0896] Computational system 626 preferably includes one or more memorymediums on which computer programs according to various embodiments maybe stored. The term “memory medium” may include an installation medium,e.g., CD-ROM or floppy disks 630, a computational system memory such asDRAM, SKAM, EDO DRAM, SDRAM, DDR SDRAM, Rambus RAM, etc., or anon-volatile memory such as a magnetic media (e.g., a hard drive) oroptical storage. The memory medium may include other types of memory aswell, or combinations thereof. In addition, the memory medium may belocated in a first computer that is used to execute the programs.Alternatively, the memory medium may be located in a second computer, orother computers, connected to the first computer (e.g., over a network).In the latter case, the second computer provides the programinstructions to the first computer for execution. Also, computationalsystem 626 may take various forms, including a personal computer,mainframe computational system, workstation, network appliance, Internetappliance, personal digital assistant (PDA), television system, or otherdevice. In general, the term “computational system” can be broadlydefined to encompass any device, or system of devices, having aprocessor that executes instructions from a memory medium.

[0897] The memory medium preferably stores a software program orprograms for event-triggered transaction processing. The softwareprogram(s) may be implemented in any of various ways, includingprocedure-based techniques, component-based techniques, and/orobject-oriented techniques, among others. For example, the softwareprogram may be implemented using ActiveX controls, C++ objects,JavaBeans, Microsoft Foundation Classes (MFC), or other technologies ormethodologies, as desired. A CPU, such as host CPU 628, executing codeand data from the memory medium, includes a system/process for creatingand executing the software program or programs according to the methodsand/or block diagrams described below.

[0898] In one embodiment, the computer programs executable bycomputational system 626 may be implemented in an object-orientedprogramming language. In an object-oriented programming language, dataand related methods can be grouped together or encapsulated to form anentity known as an object. All objects in an object-oriented programmingsystem belong to a class, which can be thought of as a category of likeobjects that describes the characteristics of those objects. Each objectis created as an instance of the class by a program. The objects maytherefore be said to have been instantiated from the class. The classsets out variables and methods for objects that belong to that class.The definition of the class does not itself create any objects. Theclass may define initial values for its variables, and it normallydefines the methods associated with the class (e.g., includes theprogram code which is executed when a method is invoked). The class maythereby provide all of the program code that will be used by objects inthe class, hence maximizing re-use of code that is shared by objects inthe class.

[0899]FIG. 17 depicts a block diagram of one embodiment of computationalsystem 626 including processor 638 coupled to a variety of systemcomponents through bus bridge 640 is shown. Other embodiments arepossible and contemplated. In the depicted system, main memory 642 iscoupled to bus bridge 640 through memory bus 644, and graphicscontroller 646 is coupled to bus bridge 640 through AGP bus 648. Aplurality of PCI devices 650 and 652 are coupled to bus bridge 640through PCI bus 654. Secondary bus bridge 656 may be provided toaccommodate an electrical interface to one or more EISA or ISA devices658 through EISA/ISA bus 660. Processor 638 is coupled to bus bridge 640through CPU bus 662 and to optional L2 cache 664.

[0900] Bus bridge 640 provides an interface between processor 638, mainmemory 642, graphics controller 646, and devices attached to PCI bus654. When an operation is received from one of the devices connected tobus bridge 640, bus bridge 640 identifies the target of the operation(e.g., a particular device or, in the case of PCI bus 654, that thetarget is on PCI bus 654). Bus bridge 640 routes the operation to thetargeted device. Bus bridge 640 generally translates an operation fromthe protocol used by the source device or bus to the protocol used bythe target device or bus.

[0901] In addition to providing an interface to an ISA/EISA bus for PCIbus 654, secondary bus bridge 656 may further incorporate additionalfunctionality, as desired. An input/output controller (not shown),either external from or integrated with secondary bus bridge 656, mayalso be included within computational system 626 to provide operationalsupport for keyboard and mouse 636 and for various serial and parallelports, as desired. An external cache unit (not shown) may further becoupled to CPU bus 662 between processor 638 and bus bridge 640 in otherembodiments. Alternatively, the external cache may be coupled to busbridge 640 and cache control logic for the external cache may beintegrated into bus bridge 640. L2 cache 664 is further shown in abackside configuration to processor 638. It is noted that L2 cache 664may be separate from processor 638, integrated into a cartridge (e.g.,slot 1 or slot A) with processor 638, or even integrated onto asemiconductor substrate with processor 638.

[0902] Main memory 642 is a memory in which application programs arestored and from which processor 638 primarily executes. A suitable mainmemory 642 comprises DRAM (Dynamic Random Access Memory). For example, aplurality of banks of SDRAM (Synchronous DRAM), DDR (Double Data Rate)SDRAM, or Rambus DRAM (RDRAM) may be suitable.

[0903] PCI devices 650 and 652 are illustrative of a variety ofperipheral devices such as, for example, network interface cards, videoaccelerators, audio cards, hard or floppy disk drives or drivecontrollers, SCSI (Small Computer Systems Interface) adapters, andtelephony cards. Similarly, ISA device 658 is illustrative of varioustypes of peripheral devices, such as a modem, a sound card, and avariety of data acquisition cards such as GPIB or field bus interfacecards.

[0904] Graphics controller 646 is provided to control the rendering oftext and images on display 666. Graphics controller 646 may embody atypical graphics accelerator generally known in the art to renderthree-dimensional data structures that can be effectively shifted intoand from main memory 642. Graphics controller 646 may therefore be amaster of AGP bus 648 in that it can request and receive access to atarget interface within bus bridge 640 to thereby obtain access to mainmemory 642. A dedicated graphics bus accommodates rapid retrieval ofdata from main memory 642. For certain operations, graphics controller646 may generate PCI protocol transactions on AGP bus 648. The AGPinterface of bus bridge 640 may thus include functionality to supportboth AGP protocol transactions as well as PCI protocol target andinitiator transactions. Display 666 is any electronic display upon whichan image or text can be presented. A suitable display 666 includes acathode ray tube (“CRT”), a liquid crystal display (“LCD”), etc.

[0905] It is noted that, while the AGP, PCI, and ISA or EISA buses havebeen used as examples in the above description, any bus architecturesmay be substituted as desired. It is further noted that computationalsystem 626 may be a multiprocessing computational system includingadditional processors (e.g., processor 668 shown as an optionalcomponent of computational system 626). Processor 668 may be similar toprocessor 638. More particularly, processor 668 may be an identical copyof processor 638. Processor 668 may be connected to bus bridge 640 viaan independent bus (as shown in FIG. 17) or may share CPU bus 662 withprocessor 638. Furthermore, processor 668 may be coupled to optional L2cache 670 similar to L2 cache 664.

[0906]FIG. 18 illustrates a flowchart of a computer-implemented methodfor treating a hydrocarbon containing formation based on acharacteristic of the formation. At least one characteristic 672 may beinput into computational system 626. Computational system 626 mayprocess at least one characteristic 672 using a software executable todetermine a set of operating conditions 676 for treating the formationwith in situ process 674. The software executable may process equationsrelating to formation characteristics and/or the relationships betweenformation characteristics. At least one characteristic 672 may include,but is not limited to, an overburden thickness, depth of the formation,coal rank, vitrinite reflectance, type of formation, permeability,density, porosity, moisture content, and other organic maturityindicators, oil saturation, water saturation, volatile matter content,kerogen composition, oil chemistry, ash content, net-to-gross ratio,carbon content, hydrogen content, oxygen content, sulfur content,nitrogen content, mineralogy, soluble compound content, elementalcomposition, hydrogeology, water zones, gas zones, barren zones,mechanical properties, or top seal character. Computational system 626may be used to control in situ process 674 using determined set ofoperating conditions 676.

[0907]FIG. 19 illustrates a schematic of an embodiment used to controlan in situ conversion process (ICP) in formation 678. Barrier well 518,monitor well 616, production well 512, and heater well 520 may be placedin formation 678. Barrier well 518 may be used to control waterconditions within formation 678. Monitoring well 616 may be used tomonitor subsurface conditions in the formation, such as, but not limitedto, pressure, temperature, product quality, or fracture progression.Production well 512 may be used to produce formation fluids (e.g., oil,gas, and water) from the formation. Heater well 520 may be used toprovide heat to the formation. Formation conditions such as, but notlimited to, pressure, temperature, fracture progression (monitored, forinstance, by acoustical sensor data), and fluid quality (e.g., productquality or water quality) may be monitored through one or more of wells512, 518, 520, and 616.

[0908] Surface data such as, but not limited to, pump status (e.g., pumpon or off), fluid flow rate, surface pressure/temperature, and/or heaterpower may be monitored by instruments placed at each well or certainwells. Similarly, subsurface data such as, but not limited to, pressure,temperature, fluid quality, and acoustical sensor data may be monitoredby instruments placed at each well or certain wells. Surface data 680from barrier well 518 may include pump status, flow rate, and surfacepressure/temperature. Surface data 682 from production well 512 mayinclude pump status, flow rate, and surface pressure/temperature.Subsurface data 684 from barrier well 518 may include pressure,temperature, water quality, and acoustical sensor data. Subsurface data686 from monitoring well 616 may include pressure, temperature, productquality, and acoustical sensor data. Subsurface data 688 from productionwell 512 may include pressure, temperature, product quality, andacoustical sensor data. Subsurface data 690 from heater well 520 mayinclude pressure, temperature, and acoustical sensor data.

[0909] Surface data 680 and 682 and subsurface data 684, 686, 688, and690 may be monitored as analog data 692 from one or more measuringinstruments. Analog data 692 may be converted to digital data 694 inanalog-to-digital converter 696. Digital data 694 may be provided tocomputational system 626. Alternatively, one or more measuringinstruments may provide digital data to computational system 626.Computational system 626 may include a distributed central processingunit (CPU). Computational system 626 may process digital data 694 tointerpret analog data 692. Output from computational system 626 may beprovided to remote display 698, data storage 700, display 666, or totreatment facility 516. Treatment facility 516 may include, for example,a hydrotreating plant, a liquid processing plant, or a gas processingplant. Computational system 626 may provide digital output 702 todigital-to-analog converter 704. Digital-to-analog converter 704 mayconvert digital output 702 to analog output 706.

[0910] Analog output 706 may include instructions to control one or moreconditions of formation 678. Analog output 706 may include instructionsto control the ICP within formation 678. Analog output 706 may includeinstructions to adjust one or more parameters of the ICP. The one ormore parameters may include, but are not limited to, pressure,temperature, product composition, and product quality. Analog output 706may include instructions for control of pump status 708 or flow rate 710at barrier well 518. Analog output 706 may include instructions forcontrol of pump status 712 or flow rate 714 at production well 512.Analog output 706 may also include instructions for control of heaterpower 716 at heater well 520. Analog output 706 may include instructionsto vary one or more conditions such as pump status, flow rate, or heaterpower. Analog output 706 may also include instructions to turn on and/oroff pumps, heaters, or monitoring instruments located at each well.

[0911] Remote input data 718 may also be provided to computationalsystem 626 to control conditions within formation 678. Remote input data718 may include data used to adjust conditions of formation 678. Remoteinput data 718 may include data such as, but not limited to, electricitycost, gas or oil prices, pipeline tariffs, data from simulations, plantemissions, or refinery availability. Remote input data 718 may be usedby computational system 626 to adjust digital output 702 to a desiredvalue. In some embodiments, treatment facility data 720 may be providedto computational system 626.

[0912] An in situ conversion process (ICP) may be monitored using afeedback control process, feedforward control process, or other type ofcontrol process. Conditions within a formation may be monitored and usedwithin the feedback control process. A formation being treated using anin situ conversion process may undergo changes in mechanical propertiesdue to the conversion of solids and viscous liquids to vapors, fracturepropagation (e.g., to overburden, underburden, water tables, etc.),increases in permeability or porosity and decreases in density, moistureevaporation, and/or thermal instability of matrix minerals (leading todehydration and decarbonation reactions and shifts in stable mineralassemblages).

[0913] Remote monitoring techniques that will sense these changes inreservoir properties may include, but are not limited to, 4D (4dimension) time lapse seismic monitoring, 3D/3C (3 dimension/3component) seismic passive acoustic monitoring of fracturing, time lapse3D seismic passive acoustic monitoring of fracturing, electricalresistivity, thermal mapping, surface or downhole tilt meters, surveyingpermanent surface monuments, chemical sniffing or laser sensors forsurface gas abundance, and gravimetrics. More direct subsurface-basedmonitoring techniques may include high temperature downholeinstrumentation (such as thermocouples and other temperature sensingmechanisms, pressure sensors such as hydrophones, stress sensors, orinstrumentation in the producer well to detect gas flows on a finelyincremental basis). In certain embodiments, a “base” seismic monitoringmay be conducted, and then subsequent seismic results can be compared todetermine changes.

[0914] U.S. Pat. Nos. 6,456,566 issued to Aronstam; 5,418,335 issued toWinbow; and 4,879,696 issued to Kostelnicek et al. and U.S. StatutoryInvention Registration H1561 to Thompson describe seismic sources foruse in active acoustic monitoring of subsurface geophysical phenomena. Atime-lapse profile may be generated to monitor temporal and arealchanges in a hydrocarbon containing formation. In some embodiments,active acoustic monitoring may be used to obtain baseline geologicalinformation before treatment of a formation. During treatment of aformation, active and/or passive acoustic monitoring may be used tomonitor changes within the formation.

[0915] Simulation methods on a computer system may be used to model anin situ process for treating a formation. Simulations may determineand/or predict operating conditions (e.g., pressure, temperature, etc.),products that may be produced from the formation at given operatingconditions, and/or product characteristics (e.g., API gravity, aromaticto paraffin ratio, etc.) for the process. In certain embodiments, acomputer simulation may be used to model fluid mechanics (including masstransfer and heat transfer) and kinetics within the formation todetermine characteristics of products produced during heating of theformation. A formation may be modeled using commercially availablesimulation programs such as STARS, THERM, FLUENT, or CFX. In addition,combinations of simulation programs may be used to more accuratelydetermine or predict characteristics of the in situ process. Results ofthe simulations may be used to determine operating conditions within theformation prior to actual treatment of the formation. Results of thesimulations may also be used to adjust operating conditions duringtreatment of the formation based on a change in a property of theformation and/or a change in a desired property of a product producedfrom the formation.

[0916]FIG. 20 illustrates a flowchart of an embodiment of method 722 formodeling an in situ process for treating a hydrocarbon containingformation using a computer system. Method 722 may include providing atleast one property 724 of the formation to the computer system.Properties of the formation may include, but are not limited to,porosity, permeability, saturation, thermal conductivity, volumetricheat capacity, compressibility, composition, and number and types ofphases in the formation. Properties may also include chemicalcomponents, chemical reactions, and kinetic parameters. At least oneoperating condition 726 of the process may also be provided to thecomputer system. For instance, operating conditions may include, but arenot limited to, pressure, temperature, heating rate, heat input rate,process time, weight percentage of gases, production characteristics(e.g., flow rates, locations, compositions), and peripheral waterrecovery or injection. In addition, operating conditions may includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells.

[0917] Method 722 may include assessing at least one processcharacteristic 728 of the in situ process using simulation method 730 onthe computer system. At least one process characteristic may be assessedas a function of time from at least one property of the formation and atleast one operating condition. Process characteristics may include, butare not limited to, properties of a produced fluid such as API gravity,olefin content, carbon number distribution, ethene to ethane ratio,atomic carbon to hydrogen ratio, and ratio of non-condensablehydrocarbons to condensable hydrocarbons (gas/oil ratio). Processcharacteristics may include, but are not limited to, a pressure andtemperature in the formation, total mass recovery from the formation,and/or production rate of fluid produced from the formation.

[0918] In some embodiments, simulation method 730 may include anumerical simulation method used/performed on the computer system. Thenumerical simulation method may employ finite difference methods tosolve fluid mechanics, heat transfer, and chemical reaction equations asa function of time. A finite difference method may use a body-fittedgrid system with unstructured grids to model a formation. Anunstructured grid employs a wide variety of shapes to model a formationgeometry, in contrast to a structured grid. A body-fitted finitedifference simulation method may calculate fluid flow and heat transferin a formation. Heat transfer mechanisms may include conduction,convection, and radiation. The body-fitted finite difference simulationmethod may also be used to treat chemical reactions in the formation.Simulations with a finite difference simulation method may employ closedvalue thermal conduction equations to calculate heat transfer andtemperature distributions in the formation. A finite differencesimulation method may determine values for heat injection rate data.

[0919] In an embodiment, a body-fitted finite difference simulationmethod may be well suited for simulating systems that include sharpinterfaces in physical properties or conditions. A body-fitted finitedifference simulation method may be more accurate, in certaincircumstances, than space-fitted methods due to the use of finer,unstructured grids in body-fitted methods. For instance, it may beadvantageous to use a body-fitted finite difference simulation method tocalculate heat transfer in a heater well and in the region near or closeto a heater well. The temperature profile in and near a heater well maybe relatively sharp. A region near a heater well may be referred to as a“near wellbore region.” The size or radius of a near wellbore region maydepend on the type of formation. A general criteria for determining orestimating the radius of a “near wellbore region” may be a distance atwhich heat transfer by the mechanism of convection contributessignificantly to overall heat transfer. Heat transfer in the nearwellbore region is typically limited to contributions from conductiveand/or radiative heat transfer. Convective heat transfer tends tocontribute significantly to overall heat transfer at locations wherefluids flow within the formation (i.e., convective heat transfer issignificant where the flow of mass contributes to heat transfer).

[0920] In general, the radius of a near wellbore region in a formationdecreases with both increasing convection and increasing variation ofthermal properties with temperature in the formation. For example, aheavy hydrocarbon containing formation may have a relatively small nearwellbore region due to the contribution of convection for heat transferand a large variation of thermal properties with temperature. In oneembodiment, the near wellbore region in a heavy hydrocarbon containingformation may have a radius of about 1 m to about 2 m. In otherembodiments, the radius may be between about 2 m and about 4 m.

[0921] A coal formation may also have a relatively small near wellboreregion due to a large variation of thermal properties with temperature.Alternatively, an oil shale formation may have a relatively large nearwellbore region due to the relatively small contribution of convectionfor heat transfer and a small variation in thermal properties withtemperature. For example, an oil shale formation may have a nearwellbore region with a radius between about 5 m and about 7 m. In otherembodiments, the radius may be between about 7 m and about 10 m.

[0922] In a simulation of a heater well and near wellbore region, abody-fitted finite difference simulation method may calculate the heatinput rate that corresponds to a given temperature in a heater well. Themethod may also calculate the temperature distributions both inside thewellbore and at the near wellbore region.

[0923] CFX supplied by AEA Technologies in the United Kingdom is anexample of a commercially available body-fitted finite differencesimulation method. FLUENT is another commercially available body-fittedfinite difference simulation method from FLUENT, Inc. located inLebanon, N.H. FLUENT may simulate models of a formation that includeporous media and heater wells. The porous media models may include oneor more materials and/or phases with variable fractions. The materialsmay have user-specified temperature dependent thermal properties anddensities. The user may also specify the initial spatial distribution ofthe materials in a model. In one modeling scheme of a porous media, acombustion reaction may only involve a reaction between carbon andoxygen. In a model of hydrocarbon combustion, the volume fraction andporosity of the formation tend to decrease. In addition, a gas phase maybe modeled by one or more species in FLUENT, for example, nitrogen,oxygen, and carbon dioxide.

[0924] In an embodiment, the simulation method may include a numericalsimulation method on a computer system that uses a space-fitted finitedifference method with structured grids. The space-fitted finitedifference simulation method may be a reservoir simulation method. Areservoir simulation method may calculate, but is not limited tocalculating, fluid mechanics, mass balances, heat transfer, and/orkinetics in the formation. A reservoir simulation method may beparticularly useful for modeling multiphase porous media in whichconvection (e.g., the flow of hot fluids) is a relatively importantmechanism of heat transfer.

[0925] STARS is an example of a reservoir simulation method provided byComputer Modeling Group, Ltd. of Alberta, Canada. STARS is designed forsimulating steam flood, steam cycling, steam-with-additives, dry and wetcombustion, along with many types of chemical additive processes, usinga wide range of grid and porosity models in both field and laboratoryscales. STARS includes options such as thermal applications, steaminjection, fireflood, horizontal wells, dual porosity/permeability,directional permeability, and flexible grids. STARS allows for complextemperature dependent models of thermal and physical properties. STARSmay also simulate pressure dependent chemical reactions. STARS maysimulate a formation using a combination of structured space-fittedgrids and unstructured body-fitted grids. Additionally, THERM is anexample of a reservoir simulation method provided by Scientific SoftwareIntercomp.

[0926] In certain embodiments, a simulation method may use properties ofa formation. In general, the properties of a formation for a model of anin situ process depend on the type of formation. In a model of an oilshale formation, for example, a porosity value may be used to model anamount of kerogen and hydrated mineral matter in the formation. Thekerogen and hydrated mineral matter used in a model may be determined orapproximated by the amount of kerogen and hydrated mineral matternecessary to generate the oil, gas and water produced in laboratoryexperiments. The remainder of the volume of the oil shale may be modeledas inert mineral matter, which may be assumed to remain intact at allsimulated temperatures. During a simulation, hydrated mineral matterdecomposes to produce water and minerals. In addition, kerogen pyrolyzesduring the simulation to produce hydrocarbons and other compoundsresulting in a rise in fluid porosity. In some embodiments, the changein porosity during a simulation may be determined by monitoring theamount of solids that are treated/transformed, and fluids that aregenerated.

[0927] In an embodiment of a coal formation model, the amount of coal inthe formation for the model may be determined by laboratory pyrolysisexperiments. Laboratory pyrolysis experiments may determine the amountof coal in an actual formation. The remainder of the volume may bemodeled as inert mineral matter or ash. In some embodiments, theporosity of the ash may be between approximately 5% and approximately10%. Absorbed and/or adsorbed fluid components, such as initialmoisture, may be modeled as part of a solid phase. As moisture desorbs,the fluid porosity tends to increase. The value of the fluid porosityaffects the results of the simulation since it may be used to model thechange in permeability.

[0928] An embodiment of a model of a tar sands formation may include aninert mineral matter phase and a fluid phase that includes heavyhydrocarbons. In an embodiment, the porosity of a tar sands formationmay be modeled as a function of the pressure of the formation and itsmechanical properties. For example, the porosity, φ, at a pressure, P,in a tar sands formation may be given by EQN. 2:

φ=φ_(ref)exp[c(P−P _(ref))]  (2)

[0929] where P_(ref) is a reference pressure, φ_(ref) is the porosity atthe reference pressure, and c is the formation compressibility.

[0930] Some embodiments of a simulation method may require an initialpermeability of a formation and a relationship for the dependence ofpermeability on conditions of the formation. An initial permeability ofa formation may be determined from experimental measurements of a sample(e.g., a core sample) of a formation. In some types of formations (e.g.,a coal formation), a ratio of vertical permeability to horizontalpermeability may be adjusted to take into consideration cleating in theformation.

[0931] In some embodiments, the porosity of a formation may be used tomodel the change in permeability of the formation during a simulation.For example, the permeability of oil shale often increases withtemperature due to the loss of solid matter from the decomposition ofmineral matter and the pyrolysis of kerogen. Similarly, the permeabilityof a coal formation often increases with temperature due to the loss ofsolid matter from pyrolysis. In one embodiment, the dependence ofporosity on permeability may be described by an analytical relationship.For example, the effect of pyrolysis on permeability, K, may be governedby a Carman-Kozeny type formula shown in EQN. 3:

K(φ_(f))=K ₀(φ_(f)/φ_(f,0))^(CKPower)[(1−φ_(f,0))/(1−φ_(f))]²  (3)

[0932] where φ_(f) is the current fluid porosity, φ_(f,0) is the initialfluid porosity, K₀ is the permeability at initial fluid porosity, andCKpower is a user-defined exponent. The value of CKpower may be fittedby matching or approximating the pressure gradient in an experiment in aformation. The porosity-permeability relationship 732 is plotted in FIG.21 for a value of the initial porosity of 0.935 millidarcy andCKpower=0.95.

[0933] Alternatively, in some formations, such as a tar sands formation,the permeability dependence may be expressed as shown in EQN. 4:

K(φ_(f))=K ₀×exp[k _(mul)×(φ_(f)−φ_(f,0))/(1−φ_(f,0))]  (4)

[0934] where K₀ and φ_(f,0) are the initial permeability and porosity,and k_(mul) is a user-defined grid dependent permeability multiplier. Inother embodiments, a tabular relationship rather than an analyticalexpression may be used to model the dependence of permeability onporosity. In addition, the ratio of vertical to horizontal permeabilityfor tar sands formations may be determined from experimental data.

[0935] In certain embodiments, the thermal conductivity of a model of aformation may be expressed in terms of the thermal conductivities ofconstituent materials. For example, the thermal conductivity may beexpressed in terms of solid phase components and fluid phase components.The solid phase in oil shale formations and coal formations may becomposed of inert mineral matter and organic solid matter. One or morefluid phases in the formations may include, for example, a water phase,an oil phase, and a gas phase. In some embodiments, the dependence ofthe thermal conductivity on constituent materials in an oil shaleformation may be modeled according to EQN. 5:

k _(th)=φ_(f)×(k _(th,w) ×S _(w) +k _(th,o) ×S _(o) +k _(th,g) ×S_(g))+(1−φ)×k _(th,r)+(φ−φ_(f))×k _(th,s)  (5)

[0936] where φ is the porosity of the formation, φ_(f) is theinstantaneous fluid porosity, k_(th,i) is the thermal conductivity ofphase i=(w,o, g)=(water, oil, gas), S_(i) is the saturation of phasei=(w, o, g)=(water, oil, gas), k_(th,r) is the thermal conductivity ofrock (inert mineral matter), and k_(th,s) is the thermal conductivity ofsolid-phase components. The thermal conductivity, from EQN. 5, may be afunction of temperature due to the temperature dependence of the solidphase components. The thermal conductivity also changes with temperaturedue to the change in composition of the fluid phase and porosity.

[0937] In some embodiments, a model may take into account the effect ofdifferent geological strata on properties of the formation. A propertyof a formation may be calculated for a given mineralogical composition.For example, the thermal conductivity of a model of a tar sandsformation may be calculated from EQN. 6: $\begin{matrix}{k_{th} = {k_{f}^{\varphi}{\prod\limits_{i = 1}^{n}\quad k_{i}^{c_{i{({1 - \varphi})}}}}}} & (6)\end{matrix}$

[0938] where k^(φ) _(f) is the thermal conductivity of the fluid phaseat porosity φ, k_(i) is the thermal conductivity of geological layer i,and c_(i) is the compressibility of geological layer i.

[0939] In an embodiment, the volumetric heat capacity, ρ_(b)C_(p), mayalso be modeled as a direct function of temperature. However, thevolumetric heat capacity also depends on the composition of theformation material through the density, which is affected bytemperature.

[0940] In one embodiment, properties of the formation may include one ormore phases with one or more chemical components. For example, fluidphases may include water, oil, and gas. Solid phases may include mineralmatter and organic matter. Each of the fluid phases in an in situprocess may include a variety of chemical components such ashydrocarbons, H₂, CO₂, etc. The chemical components may be products ofone or more chemical reactions, such as pyrolysis reactions, that occurin the formation. Some embodiments of a model of an in situ process mayinclude modeling individual chemical components known to be present in aformation. However, inclusion of chemical components in a model of an insitu process may be limited by available experimental composition andkinetic data for the components. In addition, a simulation method mayalso place numerical and solution time limitations on the number ofcomponents that may be modeled.

[0941] In some embodiments, one or more chemical components may bemodeled as a single component called a pseudo-component. In certainembodiments, the oil phase may be modeled by two volatilepseudo-components, a light oil and a heavy oil. The oil and at leastsome of the gas phase components are generated by pyrolysis of organicmatter in the formation. The light oil and the heavy oil may be modeledas having an API gravity that is consistent with laboratory orexperimental field data. For example, the light oil may have an APIgravity of between about 20° and about 70°. The heavy oil may have anAPI gravity less than about 20°.

[0942] In some embodiments, hydrocarbon gases in a formation of one ormore carbon numbers may be modeled as a single pseudo-component. Inother embodiments, non-hydrocarbon gases and hydrocarbon gases may bemodeled as a single component. For example, hydrocarbon gases between acarbon number of one to a carbon number of five and nitrogen andhydrogen sulfide may be modeled as a single component. In someembodiments, the multiple components modeled as a single component haverelatively similar molecular weights. A molecular weight of thehydrocarbon gas pseudo-component may be set such that thepseudo-component is similar to a hydrocarbon gas generated in alaboratory pyrolysis experiment at a specified pressure.

[0943] In some embodiments of an in situ process, the composition of thegenerated hydrocarbon gas may vary with pressure. As pressure increases,the ratio of a higher molecular weight component to a lower molecularcomponent tends to increase. For example, as pressure increases, theratio of hydrocarbon gases with carbon numbers between about three andabout five to hydrocarbon gases with one and two carbon numbers tends toincrease. Consequently, the molecular weight of the pseudo-componentthat models a mixture of component gases may vary with pressure.

[0944] TABLE 1 lists components in a model of in situ process in a coalformation according to one embodiment. Similarly, TABLE 2 listscomponents in a model of an in situ process in an oil shale formationaccording to an embodiment. TABLE 1 CHEMICAL COMPONENTS IN A MODEL OF ACOAL FORMATION. Component Phase MW H₂0 Aqueous 18.016 heavy oil Oil291.37 light oil Oil 155.21 HCgas Gas 19.512 H₂ Gas 2.016 CO₂ Gas 44.01CO Gas 28.01 N₂ Gas 28.02 O₂ Gas 32.0 Coal Solid 15.153 Coalbtm Solid14.786 Prechar Solid 14.065 Char Solid 12.72

[0945] TABLE 2 CHEMICAL COMPONENTS IN A MODEL OF AN OIL SHALE FORMATION.Component Phase MW H₂0 Aqueous 18.016 heavy oil Oil 317.96 light oil Oil154.11 HCgas Gas 26.895 H₂ Gas 2.016 CO₂ Gas 44.01 CO Gas 28.01 HydraminSolid 15.153 Kerogen Solid 15.153 Prechar Solid 12.72

[0946] As shown in TABLE 1, the hydrocarbon gases produced by thepyrolysis of coal may be grouped into a pseudo-component, HCgas. TheHCgas component may have critical properties intermediate betweenmethane and ethane. Similarly, the pseudo-component, HCgas, generatedfrom pyrolysis in an oil shale formation, as shown in TABLE 2, may havecritical properties very close to those of ethane. For both coal and oilshale, the HCgas pseudo-components may model hydrocarbons between acarbon number of about one and a carbon number of about five. Themolecular weight of the pseudo-component in TABLE 2 generally reflectsthe composition of the hydrocarbon gas that was generated in alaboratory experiment at a pressure of about 6.9 bars absolute.

[0947] In some embodiments, the solid phase in a formation may bemodeled with one or more components. For example, in a coal formationthe components may include coal and char, as shown in TABLE 1. Thecomponents in a kerogen formation may include kerogen and a hydratedmineral phase (hydramin), as shown in TABLE 2. The hydrated mineralcomponent may be included to model water and carbon dioxide generated inan oil shale formation at temperatures below a pyrolysis temperature ofkerogen. The hydrated minerals, for example, may include illite andnahcolite.

[0948] Kerogen may be the source of most or all of the hydrocarbonfluids generated by the pyrolysis. Kerogen may also be the source ofsome of the water and carbon dioxide that is generated at temperaturesbelow a pyrolysis temperature.

[0949] In an embodiment, the solid phase model may also include one ormore intermediate components that are artifacts of the reactions thatmodel the pyrolysis. For example, a coal formation may include twointermediate components, coalbtm and prechar, as shown in TABLE 1. Anoil shale formation may include at least one intermediate component,prechar, as shown in TABLE 2. The prechar solid-phase components maymodel carbon residue in a formation that may contain H₂ and lowmolecular weight hydrocarbons. Coalbtm accounts for intermediateunpyrolyzed compounds that tend to appear and disappear during thecourse of pyrolysis. In one embodiment, the number of intermediatecomponents may be increased to improve the match or agreement betweensimulation results and experimental results.

[0950] In one embodiment, a model of an in situ process may include oneor more chemical reactions. A number of chemical reactions are known tooccur in an in situ process for a hydrocarbon containing formation. Thechemical reactions may belong to one of several categories of reactions.The categories may include, but not be limited to, generation ofpre-pyrolysis water and carbon dioxide, generation of hydrocarbons,coking and cracking of hydrocarbons, formation of synthesis gas, andcombustion and oxidation of coke.

[0951] In one embodiment, the rate of change of the concentration ofspecies X due to a chemical reaction, for example:

X→products  (7)

[0952] may be expressed in terms of a rate law:

d[X]/dt=−k[X] ^(n)  (8)

[0953] Species X in the chemical reaction undergoes chemicaltransformation to the products. [X] is the concentration of species X, tis the time, k is the reaction rate constant, and n is the order of thereaction. The reaction rate constant, k, may be defined by the Arrheniusequation:

k=A exp[−E _(a) /RT]  (9)

[0954] where A is the frequency factor, E_(a) is the activation energy,R is the universal gas constant, and T is the temperature. Kineticparameters, such as k, A, E_(a), and n, may be determined fromexperimental measurements. A simulation method may include one or morerate laws for assessing the change in concentration of species in an insitu process as a function of time. Experimentally determined kineticparameters for one or more chemical reactions may be used as input tothe simulation method.

[0955] In some embodiments, the number and categories of reactions in amodel of an in situ process may depend on the availability ofexperimental kinetic data and/or numerical limitations of a simulationmethod. Generally, chemical reactions and kinetic parameters for a modelmay be chosen such that simulation results match or approximatequantitative and qualitative experimental trends.

[0956] In some embodiments, reactions that model the generation ofpre-pyrolysis water and carbon dioxide account for the bound water,carbon dioxide, and carbon monoxide generated in a temperature rangebelow a pyrolysis temperature. For example, pre-pyrolysis water may begenerated from hydrated mineral matter. In one embodiment, thetemperature range may be between about 100° C. and about 270° C. Inother embodiments, the temperature range may be between about 80° C. andabout 300° C. Reactions in the temperature range below a pyrolysistemperature may account for between about 45% and about 60% of the totalwater generated and up to about 30% of the total carbon dioxide observedin laboratory experiments of pyrolysis.

[0957] In an embodiment, the pressure dependence of the chemicalreactions may be modeled. To account for the pressure dependence, asingle reaction with variable stoichiometric coefficients may be used tomodel the generation of pre-pyrolysis fluids. Alternatively, thepressure dependence may be modeled with two or more reactions withpressure dependent kinetic parameters such as frequency factors.

[0958] For example, experimental results indicate that the reaction thatgenerates pre-pyrolysis fluids from oil shale is a function of pressure.The amount of water generated generally decreases with pressure whilethe amount of carbon dioxide generated generally increases withpressure. In an embodiment, the generation of pre-pyrolysis fluids maybe modeled with two reactions to account for the pressure dependence.One reaction may be dominant at high pressures while the other may beprevalent at lower pressures. For example, a molar stoichiometry of tworeactions according to one embodiment may be written as follows:

1 mol hydramin→0.5884 mol H₂O+0.0962 mol CO₂+0.0114 mol CO  (10)

1 mol hydramin→0.8234 mol H₂O+0.0 mol CO₂+0.0114 mol CO  (11)

[0959] Experimentally determined kinetic parameters for Reactions (10)and (11) are shown in TABLE 3. TABLE 3 shows that pressure dependence ofReactions (10) and (11) is taken into account by the frequency factor.The frequency factor increases with increasing pressure for Reaction(10), which results in an increase in the rate of product formation withpressure. The rate of product formation increases due to the increase inthe rate constant. In addition, the frequency factor decreases withincreasing pressure for Reaction (11), which results in a decrease inthe rate of product formation with increasing pressure. Therefore, thevalues of the frequency factor in TABLE 3 indicate that Reaction (10)dominates at high pressures while Reaction (11) dominates at lowpressures. In addition, the molar balances for Reactions (10) and (11)indicate that Reaction (10) generates less water and more carbon dioxidethan Reaction (11).

[0960] In one embodiment, a reaction enthalpy may be used by asimulation method such as STARS to assess the thermodynamic propertiesof a formation. In TABLES 3-8, the reaction enthalpy is a negativenumber if a chemical reaction is endothermic and positive if a chemicalreaction is exothermic. TABLE 3 KINETIC PARAMETERS OF PRE-PYROLYSISFLUID GENERATION REACTIONS IN AN OIL SHALE FORMATION. Pressure FrequencyReaction Reac- (bars Factor Activation Energy Enthalpy tion absolute)[(day)⁻¹] (kJ/kgmole) Order (kJ/kgmole) 10 1.0342 1.197 × 10⁹  125,600 10 4.482 7.938 × 10¹⁰ 7.929 2.170 × 10¹¹ 11.376 4.353 × 10¹¹ 14.824 7.545× 10¹¹ 18.271 1.197 × 10¹² 11 1.0342 1.197 × 10¹² 125,600 1 0 4.4825.176 × 10¹¹ 7.929 2.037 × 10¹¹ 11.376 6.941 × 10¹⁰ 14.824 1.810 × 10¹⁰18.271 1.197 × 10⁹ 

[0961] In other embodiments, the generation of hydrocarbons in apyrolysis temperature range in a formation may be modeled with one ormore reactions. One or more reactions may model the amount ofhydrocarbon fluids and carbon residue that are generated in a pyrolysistemperature range. Hydrocarbons generated may include light oil, heavyoil, and non-condensable gases. Pyrolysis reactions may also generatewater, H₂, and CO₂.

[0962] Experimental results indicate that the composition of productsgenerated in a pyrolysis temperature range may depend on operatingconditions such as pressure. For example, the production rate ofhydrocarbons generally decreases with pressure. In addition, the amountof produced hydrogen gas generally decreases substantially withpressure, the amount of carbon residue generally increases withpressure, and the amount of condensable hydrocarbons generally decreaseswith pressure. Furthermore, the amount of non-condensable hydrocarbonsgenerally increases with pressure such that the sum of condensablehydrocarbons and non-condensable hydrocarbons generally remainsapproximately constant with a change in pressure. In addition, the APIgravity of the generated hydrocarbons increases with pressure.

[0963] In an embodiment, the generation of hydrocarbons in a pyrolysistemperature range in an oil shale formation may be modeled with tworeactions. One of the reactions may be dominant at high pressures, theother prevailing at low pressures. For example, the molar stoichiometryof the two reactions according to one embodiment may be as follows:

1 mol kerogen→0.02691 mol H₂O+0.009588 mol heavy oil+0.01780 mol lightoil+0.04475 mol HCgas+0.01049 mol H₂+0.00541 mol CO₂+0.5827 molprechar  (12)

1 mol kerogen→0.02691 mol H₂O+0.009588 mol heavy oil+0.01780 mol lightoil+0.04475 mol HCgas+0.07930 mol H₂+0.00541 mol CO₂+0.5718 molprechar  (13)

[0964] Experimentally determined kinetic parameters are shown in TABLE4. Reactions (12) and (13) model the pressure dependence of hydrogen andcarbon residue on pressure. However, the reactions do not take intoaccount the pressure dependence of hydrocarbon production. In oneembodiment, the pressure dependence of the production of hydrocarbonsmay be taken into account by a set of cracking/coking reactions.Alternatively, pressure dependence of hydrocarbon production may bemodeled by hydrocarbon generation reactions without cracking/cokingreactions. TABLE 4 KINETIC PARAMETERS OF PRE-PYROLYSIS GENERATIONREACTIONS IN AN OIL SHALE FORMATION. Pressure Frequency Reaction Reac-(bars Factor Activation Energy Enthalpy tion absolute) [(day)⁻¹](kJ/kgmole) Order (kJ/kgmole) 12 1.0342 1.000 × 10⁹  161600 1 0 4.4822.620 × 10¹² 7.929 2.610 × 10¹² 11.376 1.975 × 10¹² 14.824 1.620 × 10¹²18.271 1.317 × 10¹² 13 1.0342 4.935 × 10¹² 161600 1 0 4.482 1.195 × 10¹²7.929 2.940 × 10¹¹ 11.376 7.250 × 10¹⁰ 14.824 1.840 × 10¹⁰ 18.271 1.100× 10¹⁰

[0965] In one embodiment, one or more reactions may model the crackingand coking in a formation. Cracking reactions involve the reaction ofcondensable hydrocarbons (e.g., light oil and heavy oil) to form lightercompounds (e.g., light oil and non-condensable gases) and carbonresidue. The coking reactions model the polymerization and condensationof hydrocarbon molecules. Coking reactions lead to formation of char,lower molecular weight hydrocarbons, and hydrogen. Gaseous hydrocarbonsmay undergo coking reactions to form carbon residue and H₂. Coking andcracking may account for the deposition of coke in the vicinity ofheater wells where the temperature may be substantially greater than apyrolysis temperature. For example, the molar stoichiometry of thecracking and coking reactions in an oil shale formation according to oneembodiment may be as follows:

1 mol heavy oil (gas phase)→1.8530 mol light oil+0.045 mol HCgas+2.4515mol prechar  (14)

1 mol light oil (gas phase)→5.730 mol HCgas  (15)

1 mol heavy oil (liquid phase)→0.2063 mol light oil+2.365 molHCgas+17.497 mol prechar  (16)

1 mol light oil (liquid phase)→0.5730 mol HCgas+10.904 mol prechar  (17)

1 mol HCgas→2.8 mol H₂+1.6706 mol char  (18)

[0966] Kinetic parameters for Reactions 14 to 18 are listed in TABLE 5.The kinetic parameters of the cracking reactions were chosen to match orapproximate the oil and gas production observed in laboratoryexperiments. The kinetics parameter of the coking reaction was derivedfrom experimental data on pyrolysis reactions in a coal experiment.TABLE 5 KINETIC PARAMETERS OF CRACKING AND COKING REACTIONS IN AN OILSHALE FORMATION. Pressure Frequency Reaction Reac- (bars FactorActivation Energy Enthalpy tion absolute) [(day)⁻¹] (kJ/kgmole) Order(kJ/kgmole) 14 1.0342 6.250 × 10¹⁶ 206034 1 0 4.482 7.929 11.376 14.82418.271 7.950 × 10¹⁶ 15 1.0342 9.850 × 10¹⁶ 219328 1 0 4.482 7.929 11.37614.824 18.271 5.850 × 10¹⁶ 16 — 2.647 × 10²⁰ 206034 1 0 17 — 3.820 ×10²⁰ 219328 1 0 18 — 7.660 × 10²⁰ 311432 1 0

[0967] In addition, reactions may model the generation of water at atemperature below or pyrolysis temperature range and the generation ofhydrocarbons at a temperature in a pyrolysis temperature range in a coalformation. For example, according to one embodiment, the reactions mayinclude:

1 mol coal→0.01894 mol H₂O+0.0004.91 mol HCgas+0.000047 mol H₂+0.0006.8mol CO₂+0.99883 mol coalbtm  (19)

1 mol coalbtm→0.02553 mol H₂O+0.00136 mol heavy oil+0.003174 mol

light oil+0.01618 mol HCgas+0.0032 mol H₂+0.005599 mol CO₂+

0.0008.26 mol CO+0.91306 mol prechar  (20)

1 mol prechar→0.02764 mol H₂O+0.05764 mol HCgas+0.02823 mol H₂+0.0154mol CO₂+0.006.465 mol CO+0.90598 mol char  (21)

[0968] The kinetic parameters of the three reactions are tabulated inTABLE 6. Reaction (19) models the generation of water in a temperaturerange below a pyrolysis temperature. Reaction (20) models the generationof hydrocarbons, such as oil and gas, generated in a pyrolysistemperature range. Reaction (21) models gas generated at temperaturesbetween about 370° C. and about 600° C. TABLE 6 KINETIC PARAMETERS OFREACTIONS IN A COAL FORMATION. Frequency Factor Activation [(day)⁻¹ ×Energy Reaction Enthalpy Reaction (mole/m³)^(order-1)] (kJ/kgmole) Order(kJ/kgmole) 19 2.069 × 10¹² 146535 5 0 20 1.895 × 10¹⁵ 201549 1.808−1282 21  1.64 × 10²  230270 9 0

[0969] Coking and cracking in a coal formation may be modeled by one ormore reactions in both the liquid phase and the gas phase. For example,the molar stoichiometry of two cracking reactions in the liquid and gasphase may be according to one embodiment:

1 mol heavy oil→0.1879 mol light oil+2.983 mol HCgas+16.038 molchar  (22)

1 mol light oil→0.7985 mol HCgas+10.977 mol char  (23)

[0970] In addition coking in a coal formation may be modeled as

1 mol HCgas→2.2 mol H₂+1.1853 mol char  (24)

[0971] Reaction (24) may model the coking of methane and ethane observedin field experiments when low carbon number hydrocarbon gases areinjected into a hot coal formation.

[0972] The kinetic parameters of reactions 22-24 are tabulated in TABLE7. The kinetic parameters for cracking were derived from literaturedata. The kinetic parameters for the coking reaction were derived fromlaboratory data on cracking. TABLE 7 KINETIC PARAMETERS OF CRACKING ANDCOKING REACTIONS IN A COAL FORMATION. Frequency Activation ReactionFactor Energy Enthalpy Reaction (day)⁻¹ (kJ/kgmole) Order (kJ/kgmole) 222.647 × 10²⁰ 206034 1 0 23  3.82 × 10²⁰ 219328 1 0 24  7.66 × 10²⁰311432 1 0

[0973] In certain embodiments, the generation of synthesis gas in aformation may be modeled by one or more reactions. For example, themolar stoichiometry of four synthesis gas reactions may be according toone embodiment:

1 mol 0.9442 char+1.0 mol CO₂→2.0 mol CO  (25)

1.0 mol CO→0.5 mol CO₂+0.4721 mol char  (26)

0.94426 mol char+1.0 mol H₂O→1.0 mol H₂+1.0 mol CO  (27)

1.0 mol H₂+1.0 mol CO→0.94426 mol char+1.0 mol H₂O  (28)

[0974] The kinetic parameters of the four reactions are tabulated inTABLE 8. Kinetic parameters for Reactions 25-28 were based on literaturedata that were adjusted to fit the results of a coal cube laboratoryexperiment. Pressure dependence of reactions in the coal formation isnot taken into account in TABLES 6, 7, and 8. In one embodiment,pressure dependence of the reactions in the coal formation may bemodeled, for example, with pressure dependent frequency factors. TABLE 8KINETIC PARAMETERS FOR SYNTHESIS GAS REACTIONS IN A COAL FORMATION.Frequency Activation Reaction Factor Energy Enthalpy Reaction (day ×bar)⁻¹ (kJ/kgmole) Order (kJ/kgmole) 25 2.47 × 10¹¹ 169970 1 −173033 26201.6 148.6 1 86516 27 6.44 × 10¹⁴ 237015 1 −135138 28 2.73 × 10⁷ 103191 1 135138

[0975] In one embodiment, a combustion and oxidation reaction of coke tocarbon dioxide may be modeled in a formation. For example, the molarstoichiometry of a reaction according to one embodiment may be:

0.9442 mol char+1.0 mol O₂→1.0 mol CO₂  (29)

[0976] Experimentally derived kinetic parameters include a frequencyfactor of 1.0×10⁴ (day)⁻¹, an activation energy of 58,614 kJ/kgmole, anorder of 1, and a reaction enthalpy of 427,977 kJ/kgmole.

[0977] In some embodiments, a model of a tar sands formation may bemodeled with the following components: bitumen (heavy oil), light oil,HCgas1, HCgas2, water, char, and prechar. According to one embodiment,an in situ process in a tar sands formation may be modeled by at leasttwo reactions:

Bitumen→light oil+HCgas1+H₂O+prechar  (30)

Prechar→HCgas2+H₂O+char  (31)

[0978] Reaction 30 models the pyrolysis of bitumen to oil and gascomponents. In one embodiment, Reaction (30). may be modeled as a 2^(nd)order reaction and Reaction (31) may be modeled as a 7^(th) orderreaction. In one embodiment, the reaction enthalpy of Reactions (30) and(31) may be zero.

[0979] In an embodiment, a method of modeling an in situ process oftreating a hydrocarbon containing formation using a computer system mayinclude simulating a heat input rate to the formation from two or moreheat sources. FIG. 22 illustrates method 734 for simulating heattransfer in a formation. Simulation method 736 may simulate heat inputrate 738 from two or more heat sources in the formation. For example,the simulation method may be a body-fitted finite difference simulationmethod. The heat may be allowed to transfer from the heat sources to aselected section of the formation. In an embodiment, the superpositionof heat from the two or more heat sources may pyrolyze at least somehydrocarbons within the selected section of the formation. In oneembodiment, two or more heat sources may be simulated with a model ofheat sources with symmetry boundary conditions.

[0980] In some embodiments, method 734 may include providing at leastone desired parameter 740 of the in situ process to the computer system.In some embodiments, desired parameter 740 may be a desired temperaturein the formation. In particular, the desired parameter may be a maximumtemperature at specific locations in the formation. In some embodiments,the desired parameter may be a desired heating rate or a desired productcomposition. Desired parameters 740 may include other parameters suchas, but not limited to, a desired pressure, process time, productionrate, time to obtain a given production rate, and/or productcomposition. Process characteristics 742 determined by simulation method736 may be compared 744 to at least one desired parameter 740. Themethod may further include controlling 746 the heat input rate from theheat sources (or some other process parameter) to achieve at least onedesired parameter. Consequently, the heat input rate from the two ormore heat sources during a simulation may be time dependent.

[0981] In an embodiment, heat injection into a formation may beinitiated by imposing a constant flux per unit area at the interfacebetween a heater and the formation. When a point in the formation, suchas the interface, reaches a specified maximum temperature, the heat fluxmay be varied to maintain the maximum temperature. The specified maximumtemperature may correspond to the maximum temperature allowed for aheater well casing (e.g., a maximum operating temperature for themetallurgy in the heater well). In one embodiment, the maximumtemperature may be between about 600° C. and about 700° C. In otherembodiments, the maximum temperature may be between about 700° C. andabout 800° C. In some embodiments, the maximum temperature may begreater than about 800° C.

[0982]FIG. 23 illustrates a model for simulating heat transfer rate in aformation. Model 748 represents an aerial view of {fraction (1/12^(th))}of a seven spot heater pattern in a formation. The pattern is composedof body-fitted grid elements 750. The model includes heater well 520 andproduction well 512. A pattern of heaters in a formation is modeled byimposing symmetry boundary conditions. The elements near the heaters andin the region near the heaters are substantially smaller than otherportions of the formation to more effectively model a steep temperatureprofile.

[0983] In some embodiments, in situ process are modeled with more thanone simulation method. FIG. 24 illustrates a flowchart of an embodimentof method 752 for modeling an in situ process for treating a hydrocarboncontaining formation using a computer system. At least one heat inputproperty 754 may be provided to the computer system. The computer systemmay include first simulation method 756. At least one heat inputproperty 754 may include a heat transfer property of the formation. Forexample, the heat transfer property of the formation may include heatcapacities or thermal conductivities of one or more components in theformation. In certain embodiments, at least one heat input property 754includes an initial heat input property of the formation. Initial heatinput properties may also include, but are not limited to, volumetricheat capacity, thermal conductivity, porosity, permeability, saturation,compressibility, composition, and the number and types of phases.Properties may also include chemical components, chemical reactions, andkinetic parameters.

[0984] In certain embodiments, first simulation method 756 may simulateheating of the formation. For example, the first simulation method maysimulate heating the wellbore and the near wellbore region. Simulationof heating of the formation may assess (i.e., estimate, calculate, ordetermine) heat injection rate data 758 for the formation. In oneembodiment, heat injection rate data may be assessed to achieve at leastone desired parameter of the formation, such as a desired temperature orcomposition of fluids produced from the formation. First simulationmethod 756 may use at least one heat input property 754 to assess heatinjection rate data 758 for the formation. First simulation method 756may be a numerical simulation method. The numerical simulation may be abody-fitted finite difference simulation method. In certain embodiments,first simulation method 756 may use at least one heat input property754, which is an initial heat input property. First simulation method756 may use the initial heat input property to assess heat inputproperties at later times during treatment (e.g., heating) of theformation.

[0985] Heat injection rate data 758 may be used as input into secondsimulation method 760. In some embodiments, heat injection rate data 758may be modified or altered for input into second simulation method 760.For example, heat injection rate data 758 may be modified as a boundarycondition for second simulation method 760. At least one property 762 ofthe formation may also be input for use by second simulation method 760.Heat injection rate data 758 may include a temperature profile in theformation at any time during heating of the formation. Heat injectionrate data 758 may also include heat flux data for the formation. Heatinjection rate data 758 may also include properties of the formation.

[0986] Second simulation method 760 may be a numerical simulation and/ora reservoir simulation method. In certain embodiments, second simulationmethod 760 may be a space-fitted finite difference simulation (e.g.,STARS). Second simulation method 760 may include simulations of fluidmechanics, mass balances, and/or kinetics within the formation. Themethod may further include providing at least one property 762 of theformation to the computer system. At least one property 762 may includechemical components, reactions, and kinetic parameters for the reactionsthat occur within the formation. At least one property 762 may alsoinclude other properties of the formation such as, but not limited to,permeability, porosities, and/or a location and orientation of heatsources, injection wells, or production wells.

[0987] Second simulation method 760 may assess at least one processcharacteristic 764 as a function of time based on heat injection ratedata 758 and at least one property 762. In some embodiments, secondsimulation method 760 may assess an approximate solution for at leastone process characteristic 764. The approximate solution may be acalculated estimation of at least one process characteristic 764 basedon the heat injection rate data and at least one property. Theapproximate solution may be assessed using a numerical method in secondsimulation method 760. At least one process characteristic 764 mayinclude one or more parameters produced by treating a hydrocarboncontaining formation in situ. For example, at least one processcharacteristic 764 may include, but is not limited to, a production rateof one or more produced fluids, an API gravity of a produced fluid, aweight percentage of a produced component, a total mass recovery fromthe formation, and operating conditions in the formation such aspressure or temperature.

[0988] In some embodiments, first simulation method 756 and secondsimulation method 760 may be used to predict process characteristicsusing parameters based on laboratory data. For example, experimentallybased parameters may include chemical components, chemical reactions,kinetic parameters, and one or more formation properties. Thesimulations may further be used to assess operating conditions that canbe used to produce-desired properties in fluids produced from theformation. In additional embodiments, then simulations may be used topredict changes in process characteristics based on changes in operatingconditions and/or formation properties.

[0989] In certain embodiments, one or more of the heat input propertiesmay be initial values of the heat input properties. Similarly, one ormore of the properties of the formation may be initial values of theproperties. The heat input properties and the reservoir properties maychange during a simulation of the formation using the first and secondsimulation methods. For example, the chemical composition, porosity,permeability, volumetric heat capacity, thermal conductivity, and/orsaturation may change with time. Consequently, the heat input rateassessed by the first simulation method may not be adequate input forthe second simulation method to achieve a desired parameter of theprocess. In some embodiments, the method may further include assessingmodified heat injection rate data at a specified time of the secondsimulation. At least one heat input property 766 of the formationassessed at the specified time of the second simulation method may beused as input by first simulation method 756 to calculate the modifiedheat input data. Alternatively, the heat input rate may be controlled toachieve a desired parameter during a simulation of the formation usingthe second simulation method.

[0990] In some embodiments, one or more model parameters for input intoa simulation method may be based on laboratory or field test data of anin situ process for treating a hydrocarbon containing formation. FIG. 25illustrates a flowchart of an embodiment of method 768 for calibratingmodel parameters to match or approximate laboratory or field data for anin situ process. Method 768 may include providing one or more modelparameters 770 for the in situ process. Model parameters 770 may includeproperties of the formation. Model parameters 770 may includerelationships for the dependence of properties on the changes inconditions, such as temperature and pressure, in the formation. Forexample, model parameters 770 may include a relationship for thedependence of porosity on pressure in the formation. Model parameters770 may also include an expression for the dependence of permeability onporosity. Model parameters 770 may include an expression for thedependence of thermal conductivity on composition of the formation.Model parameters 770 may include chemical components, the number andtypes of reactions in the formation, and kinetic parameters. Kineticparameters may include the order of a reaction, activation energy,reaction enthalpy, and frequency factor.

[0991] In some embodiments, method 768 may include assessing one or moresimulated process characteristics 772 based on the one or more modelparameters. Simulated process characteristics 772 may be assessed usingsimulation method 774. Simulation method 774 may be a body-fitted finitedifference simulation method. In some embodiments, simulation method 774may be a reservoir simulation method.

[0992] In an embodiment, simulated process characteristics 772 may becompared 776 to real process characteristics 778. Real processcharacteristics 778 may be process characteristics obtained fromlaboratory or field tests of an in situ process. Comparing processcharacteristics may include comparing simulated process characteristics772 with real process characteristics 778 as a function of time.Differences between simulated process characteristic 772 and realprocess characteristic 778 may be associated with one or more modelparameters. For example, a higher ratio of gas to oil of produced fluidsfrom a real in situ process may be due to a lack of pressure dependenceof kinetic parameters. Method 768 may further include modifying 780 theone or more model parameters such that at least one simulated processcharacteristic 772 matches or approximates at least one real processcharacteristic 778. One or more model parameters may be modified toaccount for a difference between a simulated process characteristic anda real process characteristic. For example, an additional chemicalreaction may be added to account for pressure dependence or adiscrepancy of an amount of a particular component in produced fluids.

[0993] Some embodiments may include assessing one or more modifiedsimulated process characteristics from simulation method 774 based onmodified model parameters 782. Modified model parameters may include oneor both of model parameters 770 that have been modified and that havenot been modified. In an embodiment, the simulation method may usemodified model parameters 782 to assess at least one operating conditionof the in situ process to achieve at least one desired parameter.

[0994] Method 768 may be used to calibrate model parameters forgeneration reactions of pre-pyrolysis fluids and generation ofhydrocarbons from pyrolysis. For example, field test results may show alarger amount of H₂ produced from the formation than the simulationresults. The discrepancy may be due to the generation of synthesis gasin the formation in the field test. Synthesis gas may be generated fromwater in the formation, particularly near heater wells. The temperaturesnear heater wells may approach a synthesis gas generating temperaturerange even when the majority of the formation is below synthesis gasgenerating temperatures. Therefore, the model parameters for thesimulation method may be modified to include some synthesis gasreactions.

[0995] In addition, model parameters may be calibrated to account forthe pressure dependence of the production of low molecular weighthydrocarbons in a formation. The pressure dependence may arise in bothlaboratory and field scale experiments. As pressure increases, fluidstend to remain in a laboratory vessel or a formation for longer periodsof time. The fluids tend to undergo increased cracking and/or cokingwith increased residence time in the laboratory vessel or the formation.As a result, larger amounts of lower molecular weight hydrocarbons maybe generated. Increased cracking of fluids may be more pronounced in afield scale experiment (as compared to a laboratory experiment, or ascompared to calculated cracking) due to longer residence times sincefluids may be required to pass through significant distances (e.g., tensof meters) of formation before being produced from a formation.

[0996] Simulations may be used to calibrate kinetic parameters thataccount for the pressure dependence. For example, pressure dependencemay be accounted for by introducing cracking and coking reactions into asimulation. The reactions may include pressure dependent kineticparameters to account for the pressure dependence. Kinetic parametersmay be chosen to match or approximate hydrocarbon production reactionparameters from experiments.

[0997] In certain embodiments, a simulation method based on a set ofmodel parameters may be used to design an in situ process. A field testof an in situ process based on the design may be used to calibrate themodel parameters. FIG. 26 illustrates a flowchart of an embodiment ofmethod 784 for calibrating model parameters. Method 784 may includeassessing at least one operating condition 786 of the in situ processusing simulation method 788 based on one or more model parameters.Operating conditions may include pressure, temperature, heating rate,heat input rate, process time, weight percentage of gases, peripheralwater recovery or injection. Operating conditions may also includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells. In one embodiment, at least one operating condition may beassessed such that the in situ process achieves at least one desiredparameter.

[0998] In some embodiments, at least one operating condition 786 may beused in real in situ process 790. In an embodiment, the real in situprocess may be a field test, or a field operation, operating with atleast one operating condition. The real in situ process may have one ormore real process characteristics 796. Simulation method 788 may assessone or more simulated process characteristics 792. In an embodiment,simulated process characteristics 792 may be compared 794 to realprocess characteristics 796. The one or more model parameters may bemodified such that at least one simulated process characteristic 792from a simulation of the in situ process matches or approximates atleast one real process characteristic 796 from the in situ process. Thein situ process may then be based on at least one operating condition.The method may further include assessing one or more modified simulatedprocess characteristics based on the modified model parameters 798. Insome embodiments, simulation method 788 may be used to control the insitu process such that the in situ process has at least one desiredparameter.

[0999] In some situations, a first simulation method may be moreeffective than a second simulation method in assessing processcharacteristics under a first set of conditions. In other situations,the second simulation method may be more effective in assessing processcharacteristics under a second set of conditions. A first simulationmethod may include a body-fitted finite difference simulation method. Afirst set of conditions may include, for example, a relatively sharpinterface in an in situ process. In an embodiment, a first simulationmethod may use a finer grid than a second simulation method. Thus, thefirst simulation method may be more effective in modeling a sharpinterface. A sharp interface refers to a relatively large change in oneor more process characteristics in a relatively small region in theformation. A sharp interface may include a relatively steep temperaturegradient that may exist in a near wellbore region of a heater well. Arelatively steep gradient in pressure and composition, due to pyrolysis,may also exist in the near wellbore region. A sharp interface may alsobe present at a combustion or reaction front as it propagates through aformation. A steep gradient in temperature, pressure, and compositionmay be present at a reaction front.

[1000] In certain embodiments, a second simulation method may include aspace-fitted finite difference simulation method such as a reservoirsimulation method. A second set of conditions may include conditions inwhich heat transfer by convection is significant. In addition, a secondset of conditions may also include condensation of fluids in aformation.

[1001] In some embodiments, model parameters for the second simulationmethod may be calibrated such that the second simulation methodeffectively assesses process characteristics under both the first setand the second set of conditions. FIG. 27 illustrates a flowchart of anembodiment of method 800 for calibrating model parameters for a secondsimulation method using a first simulation method. Method 800 mayinclude providing one or more model parameters 802 to a computer system.One or more first process characteristics 804 based on one or more modelparameters 802 may be assessed using first simulation method 806 inmemory on the computer system. First simulation method 806 may be abody-fitted finite difference simulation method. The model parametersmay include relationships for the dependence of properties such asporosity, permeability, thermal conductivity, and heat capacity on thechanges in conditions (e.g., temperature and pressure) in the formation.In addition, model parameters may include chemical components, thenumber and types of reactions in the formation, and kinetic parameters.Kinetic parameters may include the order of a reaction, activationenergy, reaction enthalpy, and frequency factor. Process characteristicsmay include, but are not limited to, a temperature profile, pressure,composition of produced fluids, and a velocity of a reaction orcombustion front.

[1002] In certain embodiments, one or more second processcharacteristics 808 based on one or more model parameters 802 may beassessed using second simulation method 810. Second simulation method810 may be a space-fitted finite difference simulation method, such as areservoir simulation method. One or more first process characteristics804 may be compared 812 to one or more second process characteristics808. The method may further include modifying one or more modelparameters 802 such that at least one first process characteristic 804matches or approximates at least one second process characteristic 808.For example, the order or the activation energy of the one or morechemical reactions may be modified to account for differences betweenthe first and second process characteristics. In addition, a singlereaction may be expressed as two or more reactions. In some embodiments,one or more third process characteristics based on the one or moremodified model parameters 814 may be assessed using the secondsimulation method.

[1003] In one embodiment, simulations of an in situ process for treatinga hydrocarbon containing formation may be used to design and/or controla real in situ process. Design and/or control of an in situ process mayinclude assessing at least one operating condition that achieves adesired parameter of the in situ process. FIG. 28 illustrates aflowchart of an embodiment of method 816 for the design and/or controlof an in situ process. The method may include providing to the computersystem one or more values of at least one operating condition 818 of thein situ process for use as input to simulation method 820. Thesimulation method may be a space-fitted finite difference simulationmethod such as a reservoir simulation method or it may be a body-fittedsimulation method such as FLUENT. At least one operating condition mayinclude, but is not limited to, pressure, temperature, heating rate,heat input rate, process time, weight percentage of gases, peripheralwater recovery or injection, production rate, and time to reach a givenproduction rate. In addition, operating conditions may includecharacteristics of the well pattern such as producer well location,producer well orientation, ratio of producer wells to heater wells,heater well spacing, type of heater well pattern, heater wellorientation, and distance between an overburden and horizontal heaterwells.

[1004] In one embodiment, the method may include assessing one or morevalues of at least one process characteristic 822 corresponding to oneor more values of at least one operating condition 818 from one or moresimulations using simulation method 820. In certain embodiments, a valueof at least one process characteristic may include the processcharacteristic as a function of time. A desired value of at least oneprocess characteristic 824 for the in situ process may also be providedto the computer system. An embodiment of the method may further includeassessing 826 desired value of at least one operating condition 828 toachieve the desired value of at least one process characteristic 824.The desired value of at least one operating condition 828 may beassessed from the values of at least one process characteristic 822 andvalues of at least one operating condition 818. For example, desiredvalue 828 may be obtained by interpolation of values 822 and values 818.In some embodiments, a value of at least one process characteristic maybe assessed from the desired value of at least one operating condition828 using simulation method 820. In some embodiments, an operatingcondition to achieve a desired parameter may be assessed by comparing aprocess characteristic as a function of time for different operatingconditions. In an embodiment, the method may include operating the insitu system using the desired value of at least one additional operatingcondition.

[1005] In some embodiments, a desired value of at least one operatingcondition to achieve a desired value of at least one processcharacteristic may be assessed by using a relationship between at leastone process characteristic and at least one operating condition of thein situ process. The relationship may be assessed from a simulationmethod. The relationship may be stored on a database accessible by thecomputer system. The relationship may include one or more values of atleast one process characteristic and corresponding values of at leastone operating condition. Alternatively, the relationship may be ananalytical function.

[1006] In an embodiment, a desired process characteristic may be aselected composition of fluids produced from a formation. A selectedcomposition may correspond to a ratio of non-condensable hydrocarbons tocondensable hydrocarbons. In certain embodiments, increasing thepressure in the formation may increase the ratio of non-condensablehydrocarbons to condensable hydrocarbons of produced fluids. Thepressure in the formation may be controlled by increasing the pressureat a production well in an in situ process. In some embodiments, otheroperating condition may be controlled simultaneously (e.g., the heatinput rate).

[1007] In an embodiment, the pressure corresponding to the selectedcomposition may be assessed from two or more simulations at two or morepressures. In one embodiment, at least one of the pressures of thesimulations may be estimated from EQN. 32: $\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (32)\end{matrix}$

[1008] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the desired process characteristic for a given type of formation.Values of A and B may be assessed from experimental data for a processcharacteristic in a given formation and may be used as input to EQN. 32.The pressure corresponding to the desired value of the processcharacteristic may then be estimated for use as input into a simulation.

[1009] The two or more simulations may provide a relationship betweenpressure and the composition of produced fluids. The pressurecorresponding to the desired composition may be interpolated from therelationship. A simulation at the interpolated pressure may be performedto assess a composition and one or more additional processcharacteristics. The accuracy of the interpolated pressure may beassessed by comparing the selected composition with the composition fromthe simulation. The pressure at the production well may be set to theinterpolated pressure to obtain produced fluids with the selectedcomposition.

[1010] In certain embodiments, the pressure of a formation may bereadily controlled at certain stages of an in situ process. At somestages of the in situ process, however, pressure control may berelatively difficult. For example, during a relatively short period oftime after heating has begun, the permeability of the formation may berelatively low. At such early stages, the heat transfer front at whichpyrolysis occurs may be at a relatively large distance from a producerwell (i.e., the point at which pressure may be controlled). Therefore,there may be a significant pressure drop between the producer well andthe heat transfer front. Consequently, adjusting the pressure at aproducer well may have a relatively small influence on the pressure atwhich pyrolysis occurs at early stages of the in situ process. At laterstages of the in situ process when permeability has developed relativelyuniformly throughout the formation, the pressure of the producer wellcorresponds to the pressure in the formation. Therefore, the pressure atthe producer well may be used to control the pressure at which pyrolysisoccurs.

[1011] In some embodiments, a similar procedure may be followed toassess heater well pattern and producer well pattern characteristicsthat correspond to a desired process characteristic. For example, arelationship between the spacing of the heater wells and composition ofproduced fluids may be obtained from two or more simulations withdifferent heater well spacings.

[1012] FIGS. 296-307 depict results of simulations of in situ treatmentof tar sands formations. The simulations used EQN. 4 for modeling thepermeability of the tar sand formation. EQNS. 5 or 6 were used formodeling the thermal conductivity. Chemical reactions in the formationwere modeled with EQNS. 30 and 31. The heat injection rate wascalculated using CFX. A constant heat input rate of about 1640 Watts/mwas imposed at the casing interface. When the interface temperaturereached about 760° C., the heat input rate was controlled to maintainthe temperature of the interface at about 760° C. The approximate heatinput rate to maintain the interface temperature at about 760° C. wasused as input into STARS. STARS was then used to calculate the resultsin FIGS. 296-307.

[1013] The data from these simulations may be used to predict or assessoperating conditions and/or process characteristics for in situtreatment of tar sands formations. Similar simulations may be used topredict or assess operating conditions and/or process characteristicsfor treatment of other hydrocarbon containing formations (e.g., coal oroil shale formations).

[1014] In one embodiment, a simulation method on a computer system maybe used in a method for modeling one or more stages of a process fortreating a hydrocarbon containing formation in situ. The simulationmethod may be, for example, a reservoir simulation method. Thesimulation method may simulate heating of the formation, fluid flow,mass transfer, heat transfer, and chemical reactions in one or more ofthe stages of the process. In some embodiments, the simulation methodmay also simulate removal of contaminants from the formation, recoveryof heat from the formation, and injection of fluids into the formation.

[1015] Method 830 of modeling the one or more stages of a treatmentprocess is depicted in a flowchart in FIG. 29. The one or more stagesmay include heating stage 832, pyrolyzation stage 834, synthesis gasgeneration stage 836, remediation stage 838, and/or shut-in stage 840.Method 830 may include providing at least one property 842 of theformation to the computer system. In addition, operating conditions 844,846, 848, 850, and/or 852 for one or more of the stages of the in situprocess may be provided to the computer system. Operating conditions mayinclude, but not be limited to, pressure, temperature, heating rates,etc. In addition, operating conditions of a remediation stage mayinclude a flow rate of ground water and injected water into theformation, size of treatment area, and type of drive fluid.

[1016] In certain embodiments, method 830 may include assessing processcharacteristics 854, 856, 858, 860, and/or 862 of the one or more stagesusing the simulation method. Process characteristics may includeproperties of a produced fluid such as API gravity and gas/oil ratio.Process characteristics may also include a pressure and temperature inthe formation, total mass recovery from the formation, and productionrate of fluid produced from the formation. In addition, a processcharacteristic of the remediation stage may include the type andconcentration of contaminants remaining in the formation.

[1017] In one embodiment, a simulation method may be used to assessoperating conditions of at least one of the stages of an in situ processthat results in desired process characteristics. FIG. 30 illustrates aflowchart of an embodiment of method 864 for designing and controllingheating stage 866, pyrolyzation stage 868, synthesis-gas generatingstage 870, remediation stage 872, and/or shut-in stage 874 of an in situprocess with a simulation method on a computer system. The method mayinclude providing sets of operating conditions 876, 878, 880, 882,and/or 884 for at least one of the stages of the in situ process. Inaddition, desired process characteristics 886, 888, 890, 892, and/or 894for at least one of the stages of the in situ process may also beprovided. Method 864 may include assessing at least one additionaloperating condition 896, 898, 900, 902, and/or 904 for at least one ofthe stages that achieves the desired process characteristics of one ormore stages.

[1018] In an embodiment, in situ treatment of a hydrocarbon containingformation may substantially change physical and mechanical properties ofthe formation. The physical and mechanical properties may be affected bychemical properties of a formation, operating conditions, and processcharacteristics.

[1019] Changes in physical and mechanical properties due to treatment ofa formation may result in deformation of the formation. Deformationcharacteristics may include, but are not limited to, subsidence,compaction, heave, and shear deformation. Subsidence is a verticaldecrease in the surface of a formation over a treated portion of aformation. Heave is a vertical increase at the surface above a treatedportion of a formation. Surface displacement may result from severalconcurrent subsurface effects, such as the thermal expansion of layersof the formation, the compaction of the richest and weakest layers, andthe constraining force exerted by cooler rock that surrounds the treatedportion of the formation. In general, in the initial stages of heating aformation, the surface above the treated portion may show a heave due tothermal expansion of incompletely pyrolyzed formation material in thetreated portion of the formation. As a significant portion of formationbecomes pyrolyzed, the formation is weakened and pore pressure in thetreated portion declines. The pore pressure is the pressure of theliquid and gas that exists in the pores of a formation. The porepressure may be influenced by the thermal expansion of the organicmatter in the formation and the withdrawal of fluids from the formation.The decrease in the pore pressure tends to increase the effective stressin the treated portion. Since the pore pressure affects the effectivestress on the treated portion of a formation, pore pressure influencesthe extent of subsurface compaction in the formation. Compaction,another deformation characteristic, is a vertical decrease of asubsurface portion above or in the treated portion of the formation. Inaddition, shear deformation of layers both above and in the treatedportion of the formation may also occur. In some embodiments,deformation may adversely affect the in situ treatment process. Forexample, deformation may seriously damage treatment facilities andwellbores.

[1020] In certain embodiments, an in situ treatment process may bedesigned and controlled such that the adverse influence of deformationis minimized or substantially eliminated. Computer simulation methodsmay be useful for design and control of an in situ process sincesimulation methods may predict deformation characteristics. For example,simulation methods may predict subsidence, compaction, heave, and sheardeformation in a formation from a model of an in situ process. Themodels may include physical, mechanical, and chemical properties of aformation. Simulation methods may be used to study the influence ofproperties of a formation, operating conditions, and processcharacteristics on deformation characteristics of the formation.

[1021]FIG. 31 illustrates model 906 of a formation that may be used insimulations of deformation characteristics according to one embodiment.The formation model is a vertical cross section that may include treatedportions 908 with thickness 910 and width or radius 912. Treated portion908 may include several layers or regions that vary in mineralcomposition and richness of organic matter. For example, in a model ofan oil shale formation, treated portion 908 may include layers of leankerogenous chalk, rich kerogenous chalk, and silicified kerogenouschalk. In one embodiment, treated portion 908 may be a dipping coal seamthat is at an angle to the surface of the formation. Model 906 mayinclude untreated portions such as overburden 524 and underburden 914.Overburden 524 may have thickness 916. Overburden 524 may also includeone or more portions, for example, portion 918 and portion 920 thatdiffer in composition. For example, portion 920 may have a compositionsimilar to treated portion 908 prior to treatment. Portion 918 may becomposed of organic material, soil, rock, etc. Underburden 914 mayinclude barren rock. In some embodiments, underburden 914 may includesome organic material.

[1022] In some embodiments, an in situ process may be designed such thatit includes an untreated portion or strip between treated portions ofthe formation. FIG. 32 illustrates a schematic of a strip developmentaccording to one embodiment. The formation includes treated portion 922and treated portion 924 with thicknesses 926 and widths 928 (thicknesses926 and widths 928 may vary between portion 922 and portion 924).Untreated portion 930 with width 932 separates treated portion 922 fromtreated portion 924. In some embodiments, width 932 is substantiallyless than widths 928 since only smaller sections need to remainuntreated to provide structural support. In some embodiments, the use ofan untreated portion may decrease the amount of subsidence, heave,compaction, or shear deformation at and above the treated portions ofthe formation.

[1023] In an embodiment, an in situ treatment process may be representedby a three-dimensional model. FIG. 33 depicts a schematic illustrationof a treated portion that may be modeled with a simulation. The treatedportion includes a well pattern with heat sources 508 and productionwells 512. Dashed lines 934 correspond to three planes of symmetry thatmay divide the pattern into six equivalent sections. Solid lines betweenheat sources 508 merely depict the pattern of heat sources (i.e., thesolid lines do not represent actual equipment between the heat sources).In some embodiments, a geomechanical model of the pattern may includeone of the six symmetry segments.

[1024]FIG. 34 depicts a cross section of a model of a formation for useby a simulation method according to one embodiment. The model includesgrid elements 936. Treated portion 938 is located in the lower leftcorner of the model. Grid elements in the treated portion may besufficiently small to take into account the large variations inconditions in the treated portion. In addition, distance 940 anddistance 942 may be sufficiently large such that the deformationfurthest from the treated portion is substantially negligible.Alternatively, a model may be approximated by a shape, such as acylinder. The diameter and height of the cylinder may correspond to thesize and height of the treated portion.

[1025] In certain embodiments, heat sources may be modeled by linesources that inject heat at a fixed rate. The heat sources may generatea reasonably accurate temperature distribution in the vicinity of theheat sources. Alternatively, a time-dependent temperature distributionmay be imposed as an average boundary condition.

[1026]FIG. 35 illustrates a flowchart of an embodiment of method 944 formodeling deformation due to in situ treatment of a hydrocarboncontaining formation. The method may include providing at least oneproperty 946 of the formation to a computer system. The formation mayinclude a treated portion and an untreated portion. Properties mayinclude, but are not limited to, mechanical, chemical, thermal, andphysical properties of the portions of the formation. For example, themechanical properties may include compressive strength, confiningpressure, creep parameters, elastic modulus, Poisson's ratio, cohesionstress, friction angle, and cap eccentricity. Thermal and physicalproperties may include a coefficient of thermal expansion, volumetricheat capacity, and thermal conductivity. Properties may also include theporosity, permeability, saturation, compressibility, and density of theformation. Chemical properties may include, for example, the richnessand/or organic content of the portions of the formation.

[1027] In addition, at least one operating condition 948 may be providedto the computer system. For instance, operating conditions may include,but are not limited to, pressure, temperature, process time, rate ofpressure increase, heating rate, and characteristics of the wellpattern. In addition, an operating condition may include the overburdenthickness and thickness and width or radius of the treated portion ofthe formation. An operating condition may also include untreatedportions between treated portions of the formation, along with thehorizontal distance between treated portions of a formation.

[1028] In certain embodiments, the properties may include initialproperties of the formation. Furthermore, the model may includerelationships for the dependence of the mechanical, thermal, andphysical properties on conditions such as temperature, pressure, andrichness in the treated portions of the formation. For example, thecompressive strength in the treated portion of the formation may be afunction of richness, temperature, and pressure. The volumetric heatcapacity may depend on the richness and the coefficient of thermalexpansion may be a function of the temperature and richness.Additionally, the permeability, porosity, and density may be dependentupon the richness of the formation.

[1029] In some embodiments, physical and mechanical properties for amodel of a formation may be assessed from samples extracted from ageological formation targeted for treatment. Properties of the samplesmay be measured at various temperatures and pressures. For example,mechanical properties may be measured using uniaxial, triaxial, andcreep experiments. In addition, chemical properties (e.g., richness) ofthe samples may also be measured. Richness of the samples may bemeasured by the Fischer Assay method. The dependence of properties ontemperature, pressure, and richness may then be assessed from themeasurements. In certain embodiments, the properties may be mapped on toa model using known sample locations. For instance, FIG. 36 depicts aprofile of richness versus depth in a model of an oil shale formation.The treated portion is represented by region 950. The overburden 524 andunderburden 914 (as shown in FIG. 31) of the formation are representedby region 952 and region 954, respectively. Richness is measured in m³of kerogen per metric ton of oil shale.

[1030] In certain embodiments, assessing deformation using a simulationmethod may require a material or constitutive model. A constitutivemodel relates the stress in the formation to the strain or displacement.Mechanical properties may be entered into a suitable constitutive modelto calculate the deformation of the formation. In some embodiments, theDrucker-Prager-with-cap material model may be used to model thetime-independent deformation of the formation.

[1031] In an embodiment, the time-dependent creep or secondary creepstrain of the formation may also be modeled. For example, thetime-dependent creep in a formation may be modeled with a power law inEQN. 33:

ε=C×(σ₁−σ₃)^(D) ×t  (33)

[1032] where ε is the secondary creep strain, C is a creep multiplier,σ₁ is the axial stress, σ₃ is the confining pressure, D is a stressexponent, and t is the time. The values of C and D may be obtained fromfitting experimental data. In one embodiment, the creep rate may beexpressed by EQN. 34:

dε/dt=A×(σ₁/σ_(u))^(D)  (34)

[1033] where A is a multiplier obtained from fitting experimental dataand σ_(u) is the ultimate strength in uniaxial compression.

[1034] Method 944 shown in FIG. 35 may include assessing 956 at leastone process characteristic 958 of the treated portion of the formation.At least one process characteristic 958 may be, but is not limited to, apore pressure distribution, a heat input rate, or a time dependenttemperature distribution in the treated portion of the formation.

[1035] At least one process characteristic may be assessed by asimulation method. For example, a heat input rate may be estimated usinga body-fitted finite difference simulation package such as FLUENT.Similarly, the pore pressure distribution may be assessed from aspace-fitted or body-fitted simulation method such as STARS. In otherembodiments, the pore pressure may be assessed by a finite elementsimulation method such as ABAQUS. The finite element simulation methodmay employ line sinks of fluid to simulate the performance of productionwells.

[1036] Alternatively, process characteristics such as temperaturedistribution and pore pressure distribution may be approximated by othermeans. For example, the temperature distribution may be imposed as anaverage boundary condition in the calculation of deformationcharacteristics. The temperature distribution may be estimated fromresults of detailed calculations of a heating rate of a formation. Forexample, a treated portion may be heated to a pyrolyzation temperaturefor a specified period of time by heat sources and the temperaturedistribution assessed during heating of the treated portion. In anembodiment, the heat sources may be uniformly distributed and inject aconstant amount of heat. The temperature distribution inside most of thetreated portion may be substantially uniform during the specified periodof time. Some heat may be allowed to diffuse from the treated portioninto the overburden, base rock, and lateral rock. The treated portionmay be maintained at a selected temperature for a selected period oftime after the specified period of time by injecting heat from the heatsources as needed.

[1037] Similarly, the pore pressure distribution may also be imposed asan average boundary condition. The initial pore pressure distributionmay be assumed to be lithostatic. The pore pressure distribution maythen be gradually reduced to a selected pressure during the remainder ofthe simulation of the deformation characteristics.

[1038] In some embodiments, method 944 may include assessing at leastone deformation characteristic 960 of the formation using simulationmethod 962 on the computer system as a function of time. In someembodiments, at least one deformation characteristic may be assessedfrom at least one property 946, at least one process characteristic 958,and at least one operating condition 948. In some embodiments, processcharacteristic 958 may be assessed by a simulation or processcharacteristic 958 may be measured. Deformation characteristics mayinclude, but are not limited to, subsidence, compaction, heave, andshear deformation in the formation.

[1039] Simulation method 962 may be a finite element simulation methodfor calculating elastic, plastic, and time dependent behavior ofmaterials. For example, ABAQUS is a commercially available finiteelement simulation method from Hibbitt, Karlsson & Sorensen, Inc.located in Pawtucket, R.I. ABAQUS is capable of describing the elastic,plastic, and time dependent (creep) behavior of a broad class ofmaterials such as mineral matter, soils, and metals. In general, ABAQUSmay treat materials whose properties may be specified by user-definedconstitutive laws. ABAQUS may also calculate heat transfer and treat theeffect of pore pressure variations on rock deformation.

[1040] Computer simulations may be used to assess operating conditionsof an in situ process in a formation that may result in desireddeformation characteristics. FIG. 37 illustrates a flowchart of anembodiment of method 964 for designing and controlling-an in situprocess using a computer system. The method may include providing to thecomputer system at least one set of operating conditions 966 for the insitu process. For instance, operating conditions may include pressure,temperature, process time, rate of pressure increase, heating rate,characteristics of the well pattern, the overburden thickness, thicknessand width of the treated portion of the formation and/or untreatedportions between treated portions of the formation, and the horizontaldistance between treated portions of a formation.

[1041] In addition, at least one desired deformation characteristic 968for the in situ process may be provided to the computer system. Thedesired deformation characteristic may be a selected subsidence,selected heave, selected compaction, or selected shear deformation. Insome embodiments, at least one additional operating condition 970 may beassessed using simulation method 972 that achieves at least one desireddeformation characteristic 968. A desired deformation characteristic maybe a value that does not adversely affect the operation of an in situprocess. For example, a minimum overburden necessary to achieve adesired maximum value of subsidence may be assessed. In an embodiment,at least one additional operating condition 970 may be used to operatein situ process 974.

[1042] In an embodiment, operating conditions to obtain desireddeformation characteristics may be assessed from simulations of an insitu process based on multiple operating conditions. FIG. 38 illustratesa flowchart of an embodiment of method 976 for assessing operatingconditions to obtain desired deformation characteristics. The method mayinclude providing one or more values of at least one operating condition978 to a computer system for use as input to simulation method 980. Thesimulation method may be a finite element simulation method forcalculating elastic, plastic, and creep behavior.

[1043] In some embodiments, method 976 may include assessing one or morevalues of deformation characteristics 982 using simulation method 980based on the one or more values of at least one operating condition 978.In one embodiment, a value of at least one deformation characteristicmay include the deformation characteristic as a function of time. Adesired value of at least one deformation characteristic 984 for the insitu process may also be provided to the computer system. An embodimentof the method may include assessing 986 desired value of at least oneoperating condition 988 to achieve desired value of at least onedeformation characteristic 984.

[1044] Desired value of at least one operating condition 988 may beassessed from the values of at least one deformation characteristic 982and the values of at least one operating condition 978. For example,desired value 988 may be obtained by interpolation of values 982 andvalues 978. In some embodiments, a value of at least one deformationcharacteristic may be assessed 990 from the desired value of at leastone operating condition 988 using simulation method 980. In someembodiments, an operating condition to achieve a desired deformationcharacteristic may be assessed by comparing a deformation characteristicas a function of time for different operating conditions.

[1045] In some embodiments, a desired value of at least one operatingcondition to achieve the desired value of at least one deformationcharacteristic may be assessed using a relationship between at least onedeformation characteristic and at least one operating condition of thein situ process. The relationship may be assessed using a simulationmethod. Such relationship may be stored on a database accessible by thecomputer system. The relationship may include one or more values of atleast one deformation characteristic and corresponding values of atleast one operating condition. Alternatively, the relationship may be ananalytical function.

[1046] Simulations have been used to investigate the effect of variousoperating conditions on the deformation characteristics of an oil shaleformation. In one set of simulations, the formation was modeled aseither a cylinder or a rectangular slab. In the case of a cylinder, themodel of the formation is described by a thickness of the treatedportion, a radius, and a thickness of the overburden. The rectangularslab is described by a width rather than a radius and by a thickness ofthe treated section and overburden. FIG. 39 illustrates the influence ofoperating pressure on subsidence in a cylindrical model of a formationfrom a finite element simulation. The thickness of the treated portionis 189 m, the radius of the treated portion is 305 m, and the overburdenthickness is 201 m. FIG. 39 shows the vertical surface displacement inmeters over a period of years. Curve 992 corresponds to an operatingpressure of 27.6 bars absolute and curve 994 to an operating pressure of6.9 bars absolute. It is to be understood that the surface displacementsset forth in FIG. 39 are only illustrative (actual surface displacementswill generally differ from those shown in FIG. 39). FIG. 39demonstrates, however, that increasing the operating pressure maysubstantially reduce subsidence.

[1047]FIGS. 40 and 41 illustrate the influence of the use of anuntreated portion between two treated portions. FIG. 40 is thesubsidence in a rectangular slab model with a treated portion thicknessof 189 m, treated portion width of 649 m, and overburden thickness of201 m. FIG. 41 represents the subsidence in a rectangular slab modelwith two treated portions separated by an untreated portion, as picturedin FIG. 32. The thickness of the treated portion and the overburden arethe same as the model corresponding to FIG. 40. The width of eachtreated portion is one half of the width of the treated portion of themodel in FIG. 40. Therefore, the total width of the treated portions isthe same for each model. The operating pressure in each case is 6.9 barsabsolute. As with FIG. 39, the surface displacements in FIGS. 40 and 41are only illustrative. A comparison of FIGS. 40 and 41, however, showsthat the use of an untreated portion reduces the subsidence by about25%. In addition, the initial heave is also reduced.

[1048] In another set of simulations, the calculation of the sheardeformation in a treated oil shale formation was demonstrated. The modelincluded a symmetry element of a pattern of heat sources and producerwells. Boundary conditions imposed in the model were such that thevertical planes bounding the formation were symmetry planes. FIG. 42represents the shear deformation of the formation at the location ofselected heat sources as a function of depth. Curve 996 and curve 998represent the shear deformation as a function of depth at 10 months and12 months, respectively. The curves, which correspond to the predictedshape of the heater wells, show that shear deformation increases withdepth in the formation.

[1049] In certain embodiments, a computer system may be used to operatean in situ process for treating a hydrocarbon containing formation. Thein situ process may include providing heat from one or more heat sourcesto at least one portion of the formation. The heat may transfer from theone or more heat sources to a selected section of the formation. FIG. 43illustrates method 1000 for operating an in situ process using acomputer system. Method 1000 may include operating in situ process 1002using one or more operating parameters. Operating parameters mayinclude, but are not limited to, properties of the formation, such asheat capacity, density, permeability, thermal conductivity, porosity,and/or chemical reaction data. In addition, operating parameters mayinclude operating conditions. Operating conditions may include, but arenot limited to, thickness and area of heated portion of the formation,pressure, temperature, heating rate, heat input rate, process time,production rate, time to obtain a given production rate, weightpercentage of gases, and/or peripheral water recovery or injection.Operating conditions may also include characteristics of the wellpattern such as producer well location, producer well orientation, ratioof producer wells to heater wells, heater well spacing, type of heaterwell pattern, heater well orientation, and/or distance between anoverburden and horizontal heater wells. Operating parameters may alsoinclude mechanical properties of the formation. Operating parameters mayinclude deformation characteristics, such as fracture, strain,subsidence, heave, compaction, and/or shear deformation.

[1050] In certain embodiments, at least one operating parameter 1004 ofin situ process 1002 may be provided to computer system 1006. Computersystem 1006 may be at or near in situ process 1002. Alternatively,computer system 1006 may be at a location remote from in situ process1002. The computer system may include a first simulation method forsimulating a model of in situ process 1002. In one embodiment,.the firstsimulation method may include method 722 illustrated in FIG. 20, method734 illustrated in FIG. 22, method 752 illustrated in FIG. 24, method768 illustrated in FIG. 25, method 784 illustrated in FIG. 26, method800 illustrated in FIG. 27, and/or method 816 illustrated in FIG. 28.The first simulation method may include a body-fitted finite differencesimulation method such as FLUENT or space-fitted finite differencesimulation method such as STARS. The first simulation method may performa reservoir simulation. A reservoir simulation method may be used todetermine operating parameters including, but not limited to, pressure,temperature, heating rate, heat input rate, process time, productionrate, time to obtain a given production rate, weight percentage ofgases, and peripheral water recovery or injection.

[1051] In an embodiment, the first simulation method may also calculatedeformation in a formation. A simulation method for calculatingdeformation characteristics may include a finite element simulationmethod such as ABAQUS. The first simulation method may calculatefracture progression, strain, subsidence, heave, compaction, and sheardeformation. A simulation method used for calculating deformationcharacteristics may include method 944 illustrated in FIG. 35 and/ormethod 976 illustrated in FIG. 38.

[1052] Method 1000 may include using at least one parameter 1004 with afirst simulation method and the computer system to provide assessedinformation 1008 about in situ process 1002. Operating parameters fromthe simulation may be compared to operating parameters of in situprocess 1002. Assessed information from a simulation may include asimulated relationship between one or more operating parameters with atleast one parameter 1004. For example, the assessed information mayinclude a relationship between operating parameters such as pressure,temperature, heating input rate, or heating rate and operatingparameters relating to product quality.

[1053] In some embodiments, assessed information may includeinconsistencies between operating parameters from simulation andoperating parameters from in situ process 1002. For example, thetemperature, pressure, product quality, or production rate from thefirst simulation method may differ from in situ process 1002. The sourceof the inconsistencies may be assessed from the operating parametersprovided by simulation. The source of the inconsistencies may includedifferences between certain properties used in a simulated model of insitu process 1002 and in situ process 1002. Certain properties mayinclude, but are not limited to, thermal conductivity, heat capacity,density, permeability, or chemical reaction data. Certain properties mayalso include mechanical properties such as compressive strength,confining pressure, creep parameters, elastic modulus, Poisson's ratio,cohesion stress, friction angle, and cap eccentricity.

[1054] In one embodiment, assessed information may include adjustmentsin one or more operating parameters of in situ process 1002. Theadjustments may compensate for inconsistencies between simulatedoperating parameters and operating parameters from in situ process 1002.Adjustments may be assessed from a simulated relationship between atleast one parameter 1004 and one or more operating parameters.

[1055] For example, an in situ process may have a particular hydrocarbonfluid production rate, e.g., 1 m³/day, after a particular period of time(e.g., 90 days). A theoretical temperature at an observation well (e.g.,100° C.) may be calculated using given properties of the formation.However, a measured temperature at an observation well (e.g., 80° C.)may be lower than the theoretical temperature. A simulation on acomputer system may be performed using the measured temperature. Thesimulation may provide operating parameters of the in situ process thatcorrespond to the measured temperature. The operating parameters fromsimulation may be used to assess a relationship between, for example,temperature or heat input rate and the production rate of the in situprocess. The relationship may indicate that the heat capacity or thermalconductivity of the formation used in the simulation is inconsistentwith the formation.

[1056] In some embodiments, method 1000 may further include usingassessed information 1008 to operate in situ process 1002. As usedherein, “operate” refers to controlling or changing operating conditionsof an in situ process. For example, the assessed information mayindicate that the thermal conductivity of the formation in the aboveexample is lower than the thermal conductivity used in the simulation.Therefore, the heat input rate to in situ process 1002 may be increasedto operate at the theoretical temperature.

[1057] In some embodiments, method 1000 may include obtaining 1010information 1012 from a second simulation method and the computer systemusing assessed information 1008 and desired parameter 1014. In oneembodiment, the first simulation method may be the same as the secondsimulation method. In another embodiment, the first and secondsimulation methods may be different. Simulations may provide arelationship between at least one operating parameter and at least oneother parameter. Additionally, obtained information 1012 may be used tooperate in situ process 1002.

[1058] Obtained information 1012 may include at least one operatingparameter for use in the in situ process that achieves the desiredparameter. In one embodiment, simulation method 816 illustrated in FIG.28 may be used to obtain at least one operating parameter that achievesthe desired parameter. For example, a desired hydrocarbon fluidproduction rate for an in situ process may be 6 m³/day. One or moresimulations may be used to determine the operating parameters necessaryto achieve a hydrocarbon fluid production rate of 6 m³/day. In someembodiments, model parameters used by simulation method 816 may becalibrated to account for differences observed between simulations andin situ process 1002. In one embodiment, simulation method 768illustrated in FIG. 25 may be used to calibrate model parameters. Inanother embodiment, simulation method 976 illustrated in FIG. 38 may beused to obtain at least one operating parameter that achieves a desireddeformation characteristic.

[1059]FIG. 44 illustrates a schematic of an embodiment for controllingin situ process 1016 in a formation using a computer simulation method.In situ process 1016 may include sensor 1018 for monitoring operatingparameters. Sensor 1018 may be located in a barrier well, a monitoringwell, a production well, or a heater well. Sensor 1018 may monitoroperating parameters such as subsurface and surface conditions in theformation. Subsurface conditions may include pressure, temperature,product quality, and deformation characteristics, such as fractureprogression. Sensor 1018 may also monitor surface data such as pumpstatus (i.e., on or off), fluid flow rate, surface pressure/temperature,and heater power. The surface data may be monitored with instrumentsplaced at a well.

[1060] At least one operating parameter 1020 measured by sensor 1018 maybe provided to local computer system 1022. In some embodiments,operating parameter 1020 may be provided to remote computer system 1024.Computer system 1024 may be, for example, a personal desktop computersystem, a laptop, or personal digital assistant such as a palm pilot.FIG. 45 illustrates several ways that information may be transmittedfrom in situ process 1016 to remote computer system 1024. Informationmay be transmitted by means of internet 1026 or local area network,hardwire telephone lines 1028, and/or wireless communications 1030.Wireless communications 1030 may include transmission via satellite1032. Information may be received at an in situ process site by internetor local area network, hardwire telephone lines, wirelesscommunications, and/or satellite communication systems.

[1061] As shown in FIG. 44, operating parameter 1020 may be provided tocomputer system 1022 or 1024 automatically during the treatment of aformation. Computer systems 1024, 1022 may include a simulation methodfor simulating a model of the in situ treatment process 1016. Thesimulation method may be used to obtain information 1034 about the insitu process.

[1062] In an embodiment, a simulation of in situ process 1016 may beperformed manually at a desired time. Alternatively, a simulation may beperformed automatically when a desired condition is met. For instance, asimulation may be performed when one or more operating parameters reach,or fail to reach, a particular value at a particular time. For example,a simulation may be performed when the production rate fails to reach aparticular value at a particular time.

[1063] In some embodiments, information 1034 relating to in situ process1016 may be provided automatically by computer system 1024 or 1022 foruse in controlling in situ process 1016. Information 1034 may includeinstructions relating to control of in situ process 1016. Information1034 may be transmitted from computer system 1024 via internet,hardwire, wireless, or satellite transmission. Information 1034 may beprovided to computer system 1036. Computer system 1036 may also be at alocation remote from the in situ process. Computer system 1036 mayprocess information 1034 for use in controlling in situ process 1016.For example, computer system 1036 may use information 1034 to determineadjustments in one or more operating parameters. Computer system 1036may then automatically adjust 1038 one or more operating parameters ofin situ process 1016. Alternatively, one or more operating parameters ofin situ process 1016 may be displayed and/or manually adjusted 1040.

[1064]FIG. 46 illustrates a schematic of an embodiment for controllingin situ process 1016 in a formation using information 1034. Information1034 may be obtained using a simulation method and a computer system.Information 1034 may be provided to computer system 1036. Information1034 may include information that relates to adjusting one or moreoperating parameters. Output 1042 from computer system 1036 may beprovided to display 1044, data storage 1046, or treatment facility 516.Output 1042 may also be used to automatically control conditions in theformation by adjusting one or more operating parameters. Output 1042 mayinclude instructions to adjust pump status and/or flow rate at a barrierwell 518, instructions to control flow rate at a production well 512,and/or adjust the heater power at a heater well 520. Output 1042 mayalso include instructions to heating pattern 1048 of in situ process1016. For example, an instruction may be to add one or more heater wellsat particular locations. In addition, output 1042 may includeinstructions to shut-in formation 678.

[1065] In some embodiments, output 1042 may be viewed by operators ofthe in situ process on display 1044. The operators may then use output1042 to manually adjust one or more operating parameters.

[1066]FIG. 47 illustrates a schematic of an embodiment for controllingin situ process 1016 in a formation using a simulation method and acomputer system. At least one operating parameter 1020 from in situprocess 1016 may be provided to computer system 1050. Computer system1050 may include a simulation method for simulating a model of in situprocess 1016. Computer system 1050 may use the simulation method toobtain information 1052 about in situ process 1016. Information 1052 maybe provided to data storage 1054, display 1056, and/or analyzer 1058. Inan embodiment, information 1052 may be automatically provided to in situprocess 1016. Information 1052 may then be used to operate in situprocess 1016.

[1067] Analyzer 1058 may include review and organize information 1052and/or use of the information to operate in situ process 1016. Analyzer1058 may obtain additional information 1060 from one or more simulations1062 of in situ process 1016. One or more simulations may be used toobtain additional or modified model parameters of in situ process 1016.The additional or modified model parameters may be used to furtherassess in situ process 1016. Simulation method 768 illustrated in FIG.25 may be used to determine, additional or modified model parameters.Method 768 may use at least one operating parameter 1020 and information1052 to calibrate model parameters. For example, at least one operatingparameter 1020 may be compared to at least one simulated operatingparameter. Model parameters may be modified such that at least onesimulated operating parameter matches or approximates at least oneoperating parameter 1020.

[1068] In an embodiment, analyzer 1058 may obtain 1064 additionalinformation 1066 about properties of in situ process 1016. Propertiesmay include, for example, thermal conductivity, heat capacity, porosity,or permeability of one or more portions of the formation. Properties mayalso include chemical reaction data such as chemical reactions, chemicalcomponents, and chemical reaction parameters. Properties may be obtainedfrom the literature, or from field or laboratory experiments. Forexample, properties of core samples of the treated formation may bemeasured in a laboratory. Additional information 1066 may be used tooperate in situ process 1016. Alternatively, additional information 1066may be used in one or more simulations 1062 to obtain additionalinformation 1060. For example, additional information 1060 may includeone or more operating parameters that may be used to operate in situprocess 1016. In one embodiment, method 816 illustrated in FIG. 28 maybe used to determine operating parameters to achieve a desiredparameter. The operating parameters may then be used to operate in situprocess 1016.

[1069] An in situ process for treating a formation may include treatinga selected section of the formation with a minimum average overburdenthickness. The minimum average overburden thickness may depend on a typeof hydrocarbon resource and geological formation surrounding thehydrocarbon resource. An overburden may, in some embodiments, besubstantially impermeable so that fluids produced in the selectedsection are inhibited from passing to the ground surface through theoverburden. A minimum overburden thickness may be determined as theminimum overburden needed to inhibit the escape of fluids produced inthe formation and to inhibit breakthrough to the surface due toincreased pressure within the formation during in the situ conversionprocess. Determining this minimum overburden thickness may be dependenton, for example, composition of the overburden, maximum pressure to bereached in the formation during the in situ conversion process,permeability of the overburden, composition of fluids produced in theformation, and/or temperatures in the formation or overburden. A ratioof overburden thickness to hydrocarbon resource thickness may be usedduring selection of resources to produce using an in situ thermalconversion process.

[1070] Selected factors may be used to determine a minimum overburdenthickness. These selected factors may include overall thickness of theoverburden, lithology and/or rock properties of the overburden, earthstresses, expected extent of subsidence and/or reservoir compaction, apressure of a process to be used in the formation, and extent andconnectivity of natural fracture systems surrounding the formation.

[1071] For coal, a minimum overburden thickness may be about 50 m orbetween about 25 m and 100 m. In some embodiments, a selected sectionmay have a minimum overburden pressure. A minimum overburden to resourcethickness may be between about 0.25:1 and 100:1.

[1072] For oil shale, a minimum overburden thickness may be about 100 mor between about 25 m and 300 m. A minimum overburden to resourcethickness may be between about 0.25:1 and 100:1.

[1073]FIG. 48 illustrates a flow chart of a computer-implemented methodfor determining a selected overburden thickness. Selected sectionproperties 1068 may be input into computational system 626. Propertiesof the selected section may include type of formation, density,permeability, porosity, earth stresses, etc. Selected section properties1068 may be used by a software executable to determine minimumoverburden thickness 1070 for the selected section. The softwareexecutable may be, for example, ABAQUS. The software executable mayincorporate selected factors. Computational system 626 may also run asimulation to determine minimum overburden thickness 1070. The minimumoverburden thickness may be determined so that fractures that allowformation fluid to pass to the ground surface will not form within theoverburden during an in situ process. A formation may be selected fortreatment by computational system 626 based on properties of theformation and/or properties of the overburden as determined herein.Overburden properties 1072 may also be input into computational system626. Properties of the overburden may include a type of material in theoverburden, density of the overburden, permeability of the overburden,earth stresses, etc. Computational system 626 may also be used todetermine operating conditions and/or control operating conditions foran in situ process of treating a formation.

[1074] Heating of the formation may be monitored during an in situconversion process. Monitoring heating of a selected section may includecontinuously monitoring acoustical data associated with the selectedsection. Acoustical data may include seismic data or any acoustical datathat may be measured, for example, using geophones, hydrophones, orother acoustical sensors. In an embodiment, a continuous acousticalmonitoring system can be used to monitor (e.g., intermittently orconstantly) the formation. The formation can be monitored (e.g., usinggeophones at 2 kilohertz, recording measurements every ⅛ of amillisecond) for undesirable formation conditions. In an embodiment, acontinuous acoustical monitoring system may be obtained from OyoInstruments (Houston, Tex.).

[1075] Acoustical data may be acquired by recording information usingunderground acoustical sensors located within and/or proximate a treatedformation area. Acoustical data may be used to determine a type and/orlocation of fractures developing within the selected section. Acousticaldata may be input into a computational system to determine the typeand/or location of fractures. Also, heating profiles of the formation orselected section may be determined by the computational system using theacoustical data. The computational system may run a software executableto process the acoustical data. The computational system may be used todetermine a set of operating conditions for treating the formation insitu. The computational system may also be used to control the set ofoperating conditions for treating the formation in situ based on theacoustical data. Other properties, such as a temperature of theformation, may also be input into the computational system.

[1076] An in situ conversion process may be controlled by using some ofthe production wells as injection wells for injection of steam and/orother process modifying fluids (e.g., hydrogen, which may affect aproduct composition through in situ hydrogenation).

[1077] In certain embodiments, it may be possible to use welltechnologies that may operate at high temperatures. These technologiesmay include both sensors and control mechanisms. The heat injectionprofiles and hydrocarbon vapor production may be adjusted on a morediscrete basis. It may be possible to adjust heat profiles andproduction on a bed-by-bed basis or in meter-by-meter increments. Thismay allow the ICP to compensate, for example, for different thermalproperties and/or organic contents in an interbedded lithology. Thus,cold and hot spots may be inhibited from forming, the formation may notbe overpressurized, and/or the integrity of the formation may not behighly stressed, which could cause deformations and/or damage towellbore integrity.

[1078]FIGS. 49 and 50 illustrate schematic diagrams of a plan view and across-sectional representation, respectively, of a zone being treatedusing an in situ conversion process (ICP). The ICP may causemicroseismic failures, or fractures, within the treatment zone fromwhich a seismic wave may be emitted. Treatment zone 1074 may be heatedusing heat provided from heater 540 placed in heater well 520. Pressurein treatment zone 1074 may be controlled by producing some formationfluid through heater wells 520 and/or production wells. Heat from heater540 may cause failure 1076 in a portion of the formation proximatetreatment zone 1074. Failure 1076 may be a localized rock failure withina rock volume of the formation. Failure 1076 may be an instantaneousfailure. Failure 1076 tends to produce seismic disturbance 1078. Seismicdisturbance 1078 may be an elastic or microseismic disturbance thatpropagates as a body wave in the formation surrounding the failure.Magnitude and direction of seismic disturbance as measured by sensorsmay indicate a type of macro-scale failure that occurs within theformation and/or treatment zone 1074. For example, seismic disturbance1078 may be evaluated to indicate a location, orientation, and/or extentof one or more macro-scale failures that occurred in the formation dueto heat treatment of the treatment zone 1074.

[1079] Seismic disturbance 1078 from one or more failures 1076 may bedetected with one or more sensors 1018. Sensor 1018 may be a geophone,hydrophone, accelerometer, and/or other seismic sensing device. Sensors1018 may be placed in monitoring well 616 or monitoring wells.Monitoring wells 616 may be placed in the formation proximate heaterwell 520 and treatment zone 1074. In certain embodiments, threemonitoring wells 616 are placed in the formation such that a location offailure 1076 may be triangulated using sensors 1018 in each monitoringwell.

[1080] In an in situ conversion process embodiment, sensors 1018 maymeasure a signal of seismic disturbance 1078. The signal may include awave or set of waves emitted from failure 1076. The signals may be usedto determine an approximate location of failure 1076. An approximatetime at which failure 1076 occurred, causing seismic disturbance 1078,may also be determined from the signal. This approximate location andapproximate time of failure 1076 may be used to determine if the failurecan propagate into an undesired zone of the formation. The undesiredzone may include a water aquifer, a zone of the formation undesired fortreatment, overburden 524 of the formation, and/or underburden 914 ofthe formation. An aquifer may also lie above overburden 524 or belowunderburden 914. Overburden 524 and/or underburden 914 may include oneor more rock layers that can be fractured and allow formation fluid toundesirably escape from the in situ conversion process. Sensors 1018 maybe used to monitor a progression of failure 1076 (i.e., an increase inextent of the failure) over a period of time.

[1081] In certain embodiments, a location of failure 1076 may be moreprecisely determined using a vertical distribution of sensors 1018 alongeach monitoring well 616. The vertical distribution of sensors 1018 mayalso include at least one sensor above overburden 524 and/or belowunderburden 914. The sensors above overburden 524 and/or belowunderburden 914 may be used to monitor penetration (or an absence ofpenetration) of a failure through the overburden or underburden.

[1082] If failure 1076 propagates into an undesired zone of theformation, a parameter for treatment of treatment zone 1074 controlledthrough heater well 520 may be altered to inhibit propagation of thefailure. The parameter of treatment may include a pressure in treatmentzone 1074, a volume (or flow rate) of fluids injected into the treatmentzone or removed from the treatment zone, or a heat input rate fromheater 540 into the treatment zone.

[1083]FIG. 51 illustrates a flow chart of an embodiment of a method usedto monitor treatment of a formation. Treatment plan 1080 may be providedfor a treatment zone (e.g., treatment zone 1074 in FIGS. 49 and 50).Parameters 1082 for treatment plan 1080 may include, but are not limitedto, pressure in the treatment zone, heating rate of the treatment zone,and average temperature in the treatment zone. Treatment parameters 1082may be controlled to treat through heat sources, production wells,and/or injection wells. A failure or failures may occur during treatmentof the treatment zone for a given set of parameters. Seismicdisturbances that indicate a failure may be detected by sensors placedin one or more monitoring wells in monitoring step 1084. The seismicdisturbances may be used to determine a location, a time, and/or extentof the one or more failures in determination step 1086. Determinationstep 1086 may include imaging the seismic disturbances to determine aspatial location of a failure or failures and/or a time at which thefailure or failures occurred. The location, time, and/or extent of thefailure or failures may be processed to determine if treatmentparameters 1082 can be altered to inhibit the propagation of a failureor failures into an undesired zone of the formation in interpretationstep 1088.

[1084] In an in situ conversion process embodiment, a recording systemmay be used to continuously monitor signals from sensors placed in aformation. The recording system may continuously record the signals fromsensors. The recording system may save the signals as data. The data maybe permanently saved by the recording system. The recording system maysimultaneously monitor signals from sensors. The signals may bemonitored at a selected sampling rate (e.g., about once every 0.25milliseconds). In some embodiments, two recording systems may be used tocontinuously monitor signals from sensors. A recording system may beused to record each signal from the sensors at the selected samplingrate for a desired time period. A controller may be used when therecording system is used to monitor a signal. The controller may be acomputational system or computer. In an embodiment using two or morerecording systems, the controller may direct which recording system isused for a selected time period. The controller may include a globalpositioning satellite (GPS) clock. The GPS clock may be used to providea specific time for a recording system to begin monitoring signals(e.g., a trigger time) and a time period for the monitoring of signals.The controller may provide the specific time for the recording system tobegin monitoring signals to a trigger box. The trigger box may be usedto supply a trigger pulse to a recording system to begin monitoringsignals.

[1085] A storage device may be used to record signals monitored by arecording system. The storage device may include a tape drive (e.g., ahigh-speed, high-capacity tape drive) or any device capable of recordingrelatively large amounts of data at very short time intervals. In anembodiment using two recording systems, the storage device may receivedata from the first recording system while the second recording systemis monitoring signals from one or more sensors, or vice versa. Thisenables continuous data coverage so that all or substantially allmicroseismic events that occur will be detected. In some embodiments,heat progress through the formation may be monitored by measuringmicroseismic events caused by heating of various portions of theformation.

[1086] In some embodiments, monitoring heating of a selected section ofthe formation may include electromagnetic monitoring of the selectedsection. Electromagnetic monitoring may include measuring a resistivitybetween at least two electrodes within the selected section. Data fromelectromagnetic monitoring may be input into a computational system andprocessed as described above.

[1087] A relationship between a change in characteristics of formationfluids with temperature in an in situ conversion process may bedeveloped. The relationship may relate the change in characteristicswith temperature to a heating rate and temperature for the formation.The relationship may be used to select a temperature which can be usedin an isothermal experiment to determine a quantity and quality of aproduct produced by ICP in a formation without having to use one or moreslow heating rate experiments. The isothermal experiment may beconducted in a laboratory or similar test facility. The isothermalexperiment may be conducted much more quickly than experiments thatslowly increase temperatures. An appropriate selection of a temperaturefor an isothermal experiment may be significant for prediction ofcharacteristics of formation fluids. The experiment may includeconducting an experiment on a sample of a formation (e.g., a coal sampleobtained from a coal formation). The experiment may include producinghydrocarbons from the sample.

[1088] For example, first order kinetics may be generally assumed for areaction producing a product. Assuming first order kinetics and a linearheating rate, the change in concentration (a characteristic of aformation fluid being the concentration of a component) with temperaturemay be defined by the equation:

dC/dT=−(k ₀ /m)×e ^((−E/RT)) C;  (35)

[1089] in which C is the concentration of a component, T is temperaturein Kelvin, k₀ is the frequency factor of the reaction, m is the heatingrate, E is the activation energy, and R is the gas constant.

[1090] EQN. 35 may be solved for a concentration at a selectedtemperature based on an initial concentration at a first temperature.The result is the equation: $\begin{matrix}{{C = {C_{0} \times ^{- \frac{k_{0}{RT}^{2}^{- \frac{E}{RT}}}{mE}}}};} & (36)\end{matrix}$

[1091] in which C is the concentration of a component at temperature Tand C₀ is an initial concentration of the component.

[1092] Substituting EQN. 36 into EQN. 35 yields the expression:$\begin{matrix}{{\frac{C}{T} = {{- \frac{k_{0}C_{0}}{m}} \times ^{({{- \frac{E}{RT}} - {\frac{k_{0}{RT}^{2}}{mE} \times ^{- \frac{E}{RT}}}})}}};} & (37)\end{matrix}$

[1093] which relates the change in concentration C with temperature Tfor first-order kinetics and a linear heating rate.

[1094] Typically, in application of an ICP to a hydrocarbon containingformation, the heating rate may not be linear due to temperaturelimitations in heat sources and/or in heater wells. For example, heatingmay be reduced at higher temperatures so that a temperature in a heaterwell is maintained below a desired temperature (e.g., about 650° C.).This may provide a non-linear heating rate that is relatively slowerthan a linear heating rate. The non-linear heating rate may be expressedas:

[1095]T=m×t ^(n);  (38)

[1096] in which t is time and n is an exponential decay term for theheating rate, and in which n is typically less than 1 (e.g., about0.75).

[1097] Using EQN. 38 in a first-order kinetics equation gives theexpression: $\begin{matrix}{{C = {C_{0} \times ^{({{- \frac{k_{0}{RT}^{\frac{n + 1}{n}}}{m^{1/n}n}} \times ^{- \frac{E}{RT}}})}}};} & (39)\end{matrix}$

[1098] which is a generalization of EQN. 36 for a non-linear heatingrate.

[1099] An isothermal experiment may be conducted at a selectedtemperature to determine a quality and a quantity of a product producedusing an ICP in a formation. The selected temperature may be atemperature at which half the initial concentration, C₀, has beenconverted into product (i.e., C/C₀=½). EQN. 39 may be solved for thisvalue, giving the expression: $\begin{matrix}{{{{\ln \left( \frac{k_{0}R}{m^{1/n}n} \right)} - {\ln \left( {\ln \quad 2} \right)}} = {\frac{E}{{RT}_{1/2}} - {\frac{n + 1}{n} \times \ln \quad T_{1/2}}}};} & (40)\end{matrix}$

[1100] in which T_(1/2) is the selected temperature which corresponds toconverting half of the initial concentration into product.Alternatively, an equation such as EQN. 37 may be used with a heatingrate that approximates a heating rate expected in a temperature rangewhere in situ conversion of hydrocarbons is expected. EQN. 40 may beused to determine a selected temperature based on a heating rate thatmay be expected for ICP in at least a portion of a formation. Theheating rate may be selected based on parameters such as, but notlimited to, heater well spacing, heater well installation economics(e.g., drilling costs, heater costs, etc.), and maximum heater output.At least one property of the formation may also be used to determine theheating rate. At least one property may include, but is not limited to,a type of formation, formation heat capacity, formation depth,permeability, thermal conductivity, and total organic content. Theselected temperature may be used in an isothermal experiment todetermine product quality and/or quantity. The product quality and/orquantity may also be determined at a selected pressure in the isothermalexperiment. The selected pressure may be a pressure used for an ICP. Theselected pressure may be adjusted to produce a desired product qualityand/or quantity in the isothermal experiment. The adjusted selectedpressure may be used in an ICP to produce the desired product qualityand/or quantity from the formation.

[1101] In some embodiments, EQN. 40 may be used to determine a heatingrate (m or m^(n)) used in an ICP based on results from an isothermalexperiment at a selected temperature (T_(1/2)). For example, isothermalexperiments may be performed at a variety of temperatures. The selectedtemperature may be chosen as a temperature at which a product of desiredquality and/or quantity is produced. The selected temperature may beused in EQN. 40 to determine the desired heating rate during ICP toproduce a product of the desired quality and/or quantity.

[1102] Alternatively, if a heating rate is estimated, at least in afirst instance, by optimizing costs and incomes such as heater wellcosts and the time required to produce hydrocarbons, then constants foran equation such as EQN. 40 may be determined by data from an experimentwhen the temperature is raised at a constant rate. With the constants ofEQN. 40 estimated and heating rates estimated, a temperature forisothermal experiments may be calculated. Isothermal experiments may beperformed much more quickly than experiments at anticipated heatingrates (i.e., relatively slow heating rates). Thus, the effect ofvariables (such as pressure) and the effect of applying additional gases(such as, for example, steam and hydrogen) may be determined byrelatively fast experiments.

[1103] In an embodiment, a hydrocarbon containing formation may beheated with a natural distributed combustor system located in theformation. The generated heat may be allowed to transfer to a selectedsection of the formation. A natural distributed combustor may oxidizehydrocarbons in a formation in the vicinity of a wellbore to provideheat to a selected section of the formation.

[1104] A temperature sufficient to support oxidation may be at leastabout 200° C. or 250° C. The temperature sufficient to support oxidationwill tend to vary depending on many factors (e.g., a composition of thehydrocarbons in the hydrocarbon containing formation, water content ofthe formation, and/or type and amount of oxidant). Some water may beremoved from the formation prior to heating. For example, the water maybe pumped from the formation by dewatering wells. The heated portion ofthe formation may be near or substantially adjacent to an opening in thehydrocarbon containing formation. The opening in the formation may be aheater well formed in the formation. The heated portion of thehydrocarbon containing formation may extend radially from the opening toa width of about 0.3 m to about 1.2 m. The width, however, may also beless than about 0.9 m. A width of the heated portion may vary with time.In certain embodiments, the variance depends on factors including awidth of formation necessary to generate sufficient heat duringoxidation of carbon-to maintain-the oxidation reaction without providingheat from an additional heat source.

[1105] After the portion of the formation reaches a temperaturesufficient to support oxidation, an oxidizing fluid may be provided intothe opening to oxidize at least a portion of the hydrocarbons at areaction zone or a heat source zone within the formation. Oxidation ofthe hydrocarbons will generate heat at the reaction zone. The generatedheat will in most embodiments transfer from the reaction zone to apyrolysis zone in the formation. In certain embodiments, the generatedheat transfers at a rate between about 650 watts per meter and 1650watts per meter as measured along a depth of the reaction zone. Uponoxidation of at least some of the hydrocarbons in the formation, energysupplied to the heater for initially heating the formation to thetemperature sufficient to support oxidation may be reduced or turnedoff. Energy input costs may be significantly reduced using naturaldistributed combustors, thereby providing a significantly more efficientsystem for heating the formation.

[1106] In an embodiment, a conduit may be disposed in the opening toprovide oxidizing fluid into the opening. The conduit may have floworifices or other flow control mechanisms (i.e., slits, venturi meters,valves, etc.) to allow the oxidizing fluid to enter the opening. Theterm “orifices” includes openings having a wide variety ofcross-sectional shapes including, but not limited to, circles, ovals,squares, rectangles, triangles, slits, or other regular or irregularshapes. The flow orifices may be critical flow orifices in someembodiments. The flow orifices may provide a substantially constant flowof oxidizing fluid into the opening, regardless of the pressure in theopening.

[1107] In some embodiments, the number of flow orifices may be limitedby the diameter of the orifices and a desired spacing between orificesfor a length of the conduit. For example, as the diameter of theorifices decreases, the number of flow orifices may increase, and viceversa. In addition, as the desired spacing increases, the number of floworifices may decrease, and vice versa. The diameter of the orifices maybe determined by a pressure in the conduit and/or a desired flow ratethrough the orifices. For example, for a flow rate of about 1.7 standardcubic meters per minute and a pressure of about 7 bars absolute, anorifice diameter may be about 1.3 mm with a spacing between orifices ofabout 2 m. Smaller diameter orifices may plug more readily than largerdiameter orifices. Orifices may plug for a variety of reasons. Thereasons may include, but are not limited to, contaminants in the fluidflowing in the conduit and/or solid deposition within or proximate theorifices.

[1108] In some embodiments, the number and diameter of the orifices arechosen such that a more even or nearly uniform heating profile will beobtained along a depth of the opening in the formation. A depth of aheated formation that is intended to have an approximately uniformheating profile may be greater than about 300 m, or even greater thanabout 600 m. Such a depth may vary, however, depending on, for example,a type of formation to be heated and/or a desired production rate.

[1109] In some embodiments, flow orifices may be disposed in a helicalpattern around the conduit within the opening. The flow orifices may bespaced by about 0.3 m to about 3 m between orifices in the helicalpattern. In some embodiments, the spacing may be about 1 m to about 2 mor, for example, about 1.5 m.

[1110] The flow of oxidizing fluid into the opening may be controlledsuch that a rate of oxidation at the reaction zone is controlled.Transfer of heat between incoming oxidant and outgoing oxidationproducts may heat the oxidizing fluid. The transfer of heat may alsomaintain the conduit below a maximum operating temperature of theconduit.

[1111]FIG. 52 illustrates an embodiment of a natural distributedcombustor that may heat a hydrocarbon containing formation. Conduit 1090may be placed into opening 544 in hydrocarbon layer 522. Conduit 1090may have inner conduit 1092. Oxidizing fluid source 1094 may provideoxidizing fluid 1096 into inner conduit 1092. Inner conduit 1092 mayhave orifices 1098 along its length. In some embodiments, orifices 1098may be critical flow orifices disposed in a helical pattern (or anyother pattern) along a length of inner conduit 1092 in opening 544. Forexample, orifices 1098 may be arranged in a helical pattern with adistance of about 1 m to about 2.5 m between adjacent orifices. Innerconduit 1092 may be sealed at the bottom. Oxidizing fluid 1096 may beprovided into opening 544 through orifices 1098 of inner conduit 1092.

[1112] Orifices 1098, (e.g., critical flow orifices) may be designedsuch that substantially the same flow rate of oxidizing fluid 1096 maybe provided through each orifice. Orifices 1098 may also providesubstantially uniform flow of oxidizing fluid 1096 along a length ofinner conduit 1092. Such flow may provide substantially uniform heatingof hydrocarbon layer 522 along the length of inner conduit 1092.

[1113] Packing material 1100 may enclose conduit 1090 in overburden 524of the formation. Packing material 1100 may inhibit flow of fluids fromopening 544 to surface 542. Packing material 1100 may include anymaterial that inhibits flow of fluids to surface 542 such as cement orconsolidated sand or gravel. A conduit or opening through the packingmay provide a path for oxidation products to reach the surface.

[1114] Oxidation product 1102 typically enter conduit 1090 from opening544. Oxidation product 1102 may include carbon dioxide, oxides ofnitrogen, oxides of sulfur, carbon monoxide, and/or other productsresulting from a reaction of oxygen with hydrocarbons and/or carbon.Oxidation product 1102 may be removed through conduit 1090 to surface542. Oxidation product 1102 may flow along a face of reaction zone 1104in opening 544 until proximate an upper end of opening 544 whereoxidation product 1102 may flow into conduit 1090. Oxidation product1102 may also be removed through one or more conduits disposed inopening 544 and/or in hydrocarbon layer 522. For example, oxidationproduct 1102 may be removed through a second conduit disposed in opening544. Removing oxidation product 1102 through a conduit may inhibitoxidation product 1102 from flowing to a production well disposed in theformation. Orifices 1098 may inhibit oxidation product 1102 fromentering inner conduit 1092.

[1115] A flow rate of oxidation product 1102 may be balanced with a flowrate of oxidizing fluid 1096 such that a substantially constant pressureis maintained within opening 544. For a 100 m length of heated section,a flow rate of oxidizing fluid may be between about 0.5 standard cubicmeters per minute to about 5 standard cubic meters per minute, or about1.0 standard cubic meter per minute to about 4.0 standard cubic metersper minute, or, for example, about 1.7 standard cubic meters per minute.A flow rate of oxidizing fluid into the formation may be incrementallyincreased during use to accommodate expansion of the reaction zone. Apressure in the opening may be, for example, about 8 bars absolute.Oxidizing fluid 1096 may oxidize at least a portion of the hydrocarbonsin heated portion 1106 of hydrocarbon layer 522 at reaction zone 1104.Heated portion 1106 may have been initially heated to a temperaturesufficient to support oxidation by an electric heater (as shown in FIG.53). In some embodiments, an electric heater may be placed inside orstrapped to the outside of inner conduit 1092.

[1116] In certain embodiments, controlling the pressure within opening544 may inhibit oxidation products and/or oxidation fluids from flowinginto the pyrolysis zone of the formation. In some instances, pressurewithin opening 544 may be controlled to be slightly greater than apressure in the formation to allow fluid within the opening to pass intothe formation but to inhibit formation of a pressure gradient thatallows the transport of the fluid a significant distance into theformation.

[1117] Although the heat from the oxidation is transferred to theformation, oxidation product 1102 (and excess oxidation fluid such asair) may be inhibited from flowing through the formation and/or to aproduction well within the formation. Instead, oxidation product 1102and/or excess oxidation fluid may be removed from the formation. In someembodiments, the oxidation products and/or excess oxidation fluid areremoved through conduit 1090. Removing oxidation products and/or excessoxidation fluid may allow heat from oxidation reactions to transfer tothe pyrolysis zone without significant amounts of oxidation productsand/or excess oxidation fluid entering the pyrolysis zone.

[1118] In certain embodiments, some pyrolysis product near reaction zone1104 may be oxidized in reaction zone 1104 in addition to the carbon.Oxidation of the pyrolysis product in reaction zone 1104 may provideadditional heating of hydrocarbon layer 522. When oxidation of pyrolysisproduct occurs, oxidation products from the oxidation of pyrolysisproduct may be removed near the reaction zone (e.g., through a conduitsuch as conduit 1090). Removing the oxidation products of a pyrolysisproduct may inhibit contamination of other pyrolysis products in theformation with oxidation product.

[1119] Conduit 1090 may, in some embodiments, remove oxidation product1102 from opening 544 in hydrocarbon layer 522. Oxidizing fluid 1096 ininner conduit 1092 may be heated by heat exchange with conduit 1090. Aportion of heat transfer between conduit 1090 and inner conduit 1092 mayoccur in overburden section 524. Oxidation product 1102 may be cooled bytransferring heat to oxidizing fluid 1096. Heating the incomingoxidizing fluid 1096 tends to improve the efficiency of heating theformation.

[1120] Oxidizing fluid 1096 may transport through reaction zone 1104, orheat source zone, by gas phase diffusion and/or convection. Diffusion ofoxidizing fluid 1096 through reaction zone 1104 may be more efficient atthe relatively high temperatures of oxidation. Diffusion of oxidizingfluid 1096 may inhibit development of localized overheating andfingering in the formation. Diffusion of oxidizing fluid 1096 throughhydrocarbon layer 522 is generally a mass transfer process. In theabsence of an external force, a rate of diffusion for oxidizing fluid1096 may depend upon concentration, pressure, and/or temperature ofoxidizing fluid 1096 within hydrocarbon layer 522. The rate of diffusionmay also depend upon the diffusion coefficient of oxidizing fluid 1096through hydrocarbon layer 522. The diffusion coefficient may bedetermined by measurement or calculation based on the kinetic theory ofgases. In general, random motion of oxidizing fluid 1096 may transferthe oxidizing fluid through hydrocarbon layer 522 from a region of highconcentration to a region of low concentration.

[1121] With time, reaction zone 1104 may slowly extend radially togreater diameters from opening 544 as hydrocarbons are oxidized.Reaction zone 1104 may, in many embodiments, maintain a relativelyconstant width. For example, reaction zone 1104 may extend radially at arate of less than about 0.91 m per year for a hydrocarbon containingformation. For example, for a coal formation, reaction zone 1104 mayextend radially at a rate between about 0.5 m per year to about 1 m peryear. For an oil shale formation, reaction zone 1104 may extend radiallyabout 2 m in the first year and at a lower rate in subsequent years dueto an increase in volume of reaction zone 1104 as the reaction zoneextends radially. Such a lower rate may be about 1 m per year to about1.5 m per year. Reaction zone 1104 may extend at slower rates forhydrocarbon rich formations (e.g., coal) and at faster rates forformations with more inorganic material (e.g., oil shale) since morehydrocarbons per volume are available for combustion in the hydrocarbonrich formations.

[1122] A flow rate of oxidizing fluid 1096 into opening 544 may beincreased as a diameter of reaction zone 1104 increases to maintain therate of oxidation per unit volume at a substantially steady state. Thus,a temperature within reaction zone 1104 may be maintained substantiallyconstant in some embodiments. The temperature within reaction zone 1104may be between about 650° C. to about 900° C. or, for example, about760° C. The temperature may be maintained below a temperature thatresults in production of oxides of nitrogen (NO_(x)). Oxides of nitrogenare often produced at temperatures above about 1200° C.

[1123] The temperature within reaction zone 1104 may be varied toachieve a desired heating rate of selected section 1108. The temperaturewithin reaction zone 1104 may be increased or decreased by increasing ordecreasing a flow rate of oxidizing fluid 1096 into opening 544. Atemperature of conduit 1090, inner conduit 1092, and/or anymetallurgical materials within opening 544 may be controlled to notexceed a maximum operating temperature of the material. Maintaining thetemperature below the maximum operating temperature of a material mayinhibit excessive deformation and/or corrosion of the material.

[1124] An increase in the diameter of reaction zone 1104 may allow forrelatively rapid heating of hydrocarbon layer 522. As the diameter ofreaction zone 1104 increases, an amount of heat generated per time inreaction zone 1104 may also increase. Increasing an amount of heatgenerated per time in the reaction zone will in many instances increasea heating rate of hydrocarbon layer 522 over a period of time, evenwithout increasing the temperature in the reaction zone or thetemperature at inner conduit 1092. Thus, increased heating may beachieved over time without installing additional heat sources andwithout increasing temperatures adjacent to wellbores. In someembodiments, the heating rates may be increased while allowing thetemperatures to decrease (allowing temperatures to decrease may oftenlengthen the life of the equipment used).

[1125] By utilizing the carbon in the formation as a fuel, the naturaldistributed combustor may save significantly on energy costs. Thus, aneconomical process may be provided for heating formations that wouldotherwise be economically unsuitable for heating by other types of heatsources. Using natural distributed combustors may allow fewer heaters tobe inserted into a formation for heating a desired volume of theformation as compared to heating the formation using other types of heatsources. Heating a formation using natural distributed combustors mayallow for reduced equipment costs as compared to heating the formationusing other types of heat sources.

[1126] Heat generated at reaction zone 1104 may transfer by thermalconduction to selected section 1108 of hydrocarbon layer 522. Inaddition, generated heat may transfer from a reaction zone to theselected section to a lesser extent by convective heat transfer.Selected section 1108, sometimes referred as the “pyrolysis zone,” maybe substantially adjacent to reaction zone 1104. Removing oxidationproducts (and excess oxidation fluid such as air) may allow thepyrolysis zone to receive heat from the reaction zone without beingexposed to oxidation product, or oxidants, that are in the reactionzone. Oxidation products and/or oxidation fluids may cause the formationof undesirable products if they are present in the pyrolysis zone.Removing oxidation products and/or oxidation fluids may allow a reducingenvironment to be maintained in the pyrolysis zone.

[1127] In an in situ conversion process embodiment, natural distributedcombustors may be used to heat a formation. FIG. 52 depicts anembodiment of a natural distributed combustor. A flow of oxidizing fluid1096 may be controlled along a length of opening 544 or reaction zone1104. Opening 544 may be referred to as an “elongated opening,” suchthat reaction zone 1104 and opening 544 may have a common boundary alonga determined length of the opening. The flow of oxidizing fluid may becontrolled using one or more orifices 1098 (the orifices may be criticalflow orifices). The flow of oxidizing fluid may be controlled by adiameter of orifices 1098, a number of orifices 1098, and/or by apressure within inner conduit 1092 (a pressure behind orifices 1098).Controlling the flow of oxidizing fluid may control a temperature at aface of reaction zone 1104 in opening 544. For example, an increasedflow of oxidizing fluid 1096 will tend to increase a temperature at theface of reaction zone 1104. Increasing the flow of oxidizing fluid intothe opening tends to increase a rate of oxidation of hydrocarbons in thereaction zone. Since the oxidation of hydrocarbons is an exothermicreaction, increasing the rate of oxidation tends to increase thetemperature in the reaction zone.

[1128] In certain natural distributed combustor embodiments, the flow ofoxidizing fluid 1096 may be varied along the length of inner conduit1092 (e.g., using critical flow orifices 1098) such that the temperatureat the face of reaction zone 1104 is variable. The temperature at theface of reaction zone 1104, or within opening 544, may be varied tocontrol a rate of heat transfer within reaction zone 1104 and/or aheating rate within selected section 1108. Increasing the temperature atthe face of reaction zone 1104 may increase the heating rate withinselected section 1108. A property of oxidation product 1102 may bemonitored (e.g., oxygen content, nitrogen content, temperature, etc.).The property of oxidation product 1102 may be monitored and used tocontrol input properties (e.g., oxidizing fluid input) into the naturaldistributed combustor.

[1129] A rate of diffusion of oxidizing fluid 1096 through reaction zone1104 may vary with a temperature of and adjacent to the reaction zone.In general, the higher the temperature, the faster a gas will diffusebecause of the increased energy in the gas. A temperature within theopening may be assessed (e.g., measured by a thermocouple) and relatedto a temperature of the reaction zone. The temperature within theopening may be controlled by controlling the flow of oxidizing fluidinto the opening from inner conduit 1092. For example, increasing a flowof oxidizing fluid into the opening may increase the temperature withinthe opening. Decreasing the flow of oxidizing fluid into the opening maydecrease the temperature within the opening. In an embodiment, a flow ofoxidizing fluid may be increased until a selected temperature below themetallurgical temperature limits of the equipment being used is reached.For example, the flow of oxidizing fluid can be increased until aworking temperature limit of a metal used in a conduit placed in-theopening is reached. The temperature of the metal may be directlymeasured using a thermocouple or other temperature measurement device.

[1130] In a natural distributed combustor embodiment, production ofcarbon dioxide within reaction zone 1104 may be inhibited. An increasein a concentration of hydrogen in the reaction zone may inhibitproduction of carbon dioxide within the reaction zone. The concentrationof hydrogen may be increased by transferring hydrogen into the reactionzone. In an embodiment, hydrogen may be transferred into the reactionzone from selected section 1108. Hydrogen may be produced during thepyrolysis of hydrocarbons in the selected section. Hydrogen may transferby diffusion and/or convection into the reaction zone from the selectedsection. In addition, additional hydrogen may be provided into opening544 or another opening in the formation through a conduit placed in theopening. The additional hydrogen may transfer into the reaction zonefrom opening 544.

[1131] In some natural distributed combustor embodiments, heat may besupplied to the formation from a second heat source in the wellbore ofthe natural distributed combustor. For example, an electric heater(e.g., an insulated conductor heater or a conductor-in-conduit heater)used to preheat a portion of the formation may also be used to provideheat to the formation along with heat from the natural distributedcombustor. In addition, an additional electric heater may be placed inan opening in the formation to provide additional heat to the formation.The electric heater may be used to provide heat to the formation so thatheat provided from the combination of the electric heater and thenatural distributed combustor is maintained at a constant heat inputrate. Heat input into the formation from the electric heater may bevaried as heat input from the natural distributed combustor varies, orvice versa. Providing heat from more than one type of heat source mayallow for substantially uniform heating of the formation.

[1132] In certain in situ conversion process embodiments, up to 10%,25%, or 50% of the total heat input into the formation may be providedfrom electric heaters. A percentage of heat input into the formationfrom electric heaters may be varied depending on, for example,electricity cost, natural distributed combustor heat input, etc. Heatfrom electric heaters can be used to compensate for low heat output fromnatural distributed combustors to maintain a substantially constantheating rate in the formation. If electrical costs rise, more heat maybe generated from natural distributed combustors to reduce the amount ofheat supplied by electric heaters. In some embodiments, heat fromelectric heaters may vary due to the source of electricity (e.g., solaror wind power). In such embodiments, more or less heat may be providedby natural distributed combustors to compensate for changes inelectrical heat input.

[1133] In a heat source embodiment, an electric heater may be used toinhibit a natural distributed combustor from “burning out.” A naturaldistributed combustor may “burn out” if a portion of the formation coolsbelow a temperature sufficient to support combustion. Additional heatfrom the electric heater may be needed to provide heat to the portionand/or another portion of the formation to heat a portion to atemperature sufficient to support oxidation of hydrocarbons and maintainthe natural distributed combustor heating process.

[1134] In some natural distributed combustor embodiments, electricheaters may be used to provide more heat to a formation proximate anupper portion and/or a lower portion of the formation. Using theadditional heat from the electric heaters may compensate for heat lossesin the upper and/or lower portions of the formation. Providingadditional heat with the electric heaters proximate the upper and/orlower portions may produce more uniform heating of the formation. Insome embodiments, electric heaters may be used for similar purposes(e.g., provide heat at upper and/or lower portions, provide supplementalheat, provide heat to maintain a minimum combustion temperature, etc.)in combination with other types of fueled heaters, such as flamelessdistributed combustors or downhole combustors.

[1135] In some in situ conversion process embodiments, exhaust fluidsfrom a fueled heater (e.g., a natural distributed combustor or downholecombustor) may be used in an air compressor located at a surface of theformation proximate an opening used for the fueled heater. The exhaustfluids may be used to drive the air compressor and reduce a costassociated with compressing air for use in the fueled heater.Electricity may also be generated using the exhaust fluids in a turbineor similar device. In some embodiments, fluids (e.g., oxidizing fluidand/or fuel) used for one or more fueled heaters may be provided using acompressor or a series of compressors. A compressor may provideoxidizing fluid and/or fuel for one heater or more than one heater. Inaddition, oxidizing fluid and/or fuel may be provided from a centralizedfacility for use in a single heater or more than one heater.

[1136] Pyrolysis of hydrocarbons, or other heat-controlled processes,may take place in heated selected section 1108. Selected section 1108may be at a temperature between about 270° C. and about 400° C. forpyrolysis. The temperature of selected section 1108 may be increased byheat transfer from reaction zone 1104.

[1137] A temperature within opening 544 may be monitored with athermocouple disposed in opening 544. Alternatively, a thermocouple maybe coupled to conduit 1090 and/or disposed on a face of reaction zone1104. Power input or oxidant introduced into the formation may becontrolled based upon the monitored temperature to maintain thetemperature in a selected range. The selected range may vary or bevaried depending on location of the thermocouple, a desired heating rateof hydrocarbon layer 522, and other factors. If a temperature withinopening 544 falls below a minimum temperature of the selectedtemperature range, the flow rate of oxidizing fluid 1096 may beincreased to increase combustion and thereby increase the temperaturewithin opening 544.

[1138] In certain embodiments, one or more natural distributedcombustors may be placed along strike of a hydrocarbon layer and/orhorizontally. Placing natural distributed combustors along strike orhorizontally may reduce pressure differentials along the heated lengthof the heat source. Reduced pressure differentials may make thetemperature generated along a length of the heater more uniform andeasier to control.

[1139] In some embodiments, presence of air or oxygen (O₂) in oxidationproduct 1102 may be monitored. Alternatively, an amount of nitrogen,carbon monoxide, carbon dioxide, oxides of nitrogen, oxides of sulfur,etc. may be monitored in oxidation product 1102. Monitoring thecomposition and/or quantity of exhaust products (e.g., oxidation product1102) may be useful for heat balances, for process diagnostics, processcontrol, etc.

[1140]FIG. 54 illustrates a cross-sectional representation of anembodiment of a natural distributed combustor having a second conduit1110 disposed in opening 544. Second conduit 1110 may be used to removeoxidation products from opening 544. Second conduit 1110 may haveorifices 1098 disposed along its length. In certain embodiments,oxidation products are removed from an upper region of opening 544through orifices 1098 disposed on second conduit 1110. Orifices 1098 maybe disposed along the length of conduit 1110 such that more oxidationproducts are removed from the upper region of opening 544.

[1141] In certain natural distributed combustor embodiments, orifices1098 on second conduit 1110 may face away from orifices 1098 on innerconduit 1092. The orientation may inhibit oxidizing fluid providedthrough inner conduit 1092 from passing directly into second conduit1110.

[1142] In some embodiments, second conduit 1110 may have a higherdensity of orifices 1098 (and/or relatively larger diameter orifices1098) towards the upper region of opening 544. The preferential removalof oxidation products from the upper region of opening 544 may produce asubstantially uniform concentration of oxidizing fluid along the lengthof opening 544. Oxidation products produced from reaction zone 1104 tendto be more concentrated proximate the upper region of opening 544. Thelarge concentration of oxidation product 1102 in the upper region ofopening 544 tends to dilute a concentration of oxidizing fluid 1096 inthe upper region. Removing a significant portion of the moreconcentrated oxidation products from the upper region of opening 544 mayproduce a more uniform concentration of oxidizing fluid 1096 throughoutopening 544. Having a more uniform concentration of oxidizing fluidthroughout the opening may produce a more uniform driving force foroxidizing fluid to flow into reaction zone 1104. The more uniformdriving force may produce a more uniform oxidation rate within reactionzone 1104, and thus produce a more uniform heating rate in selectedsection 1108 and/or a more uniform temperature within opening 544.

[1143] In a natural distributed combustor embodiment, the concentrationof air and/or oxygen in the reaction zone may be controlled. A more evendistribution of oxygen (or oxygen concentration) in the reaction zonemay be desirable. The rate of reaction may be controlled as a functionof the rate in which oxygen diffuses in the reaction zone. The rate ofoxygen diffusion correlates to the oxygen concentration. Thus,controlling the oxygen concentration in the reaction zone (e.g., bycontrolling oxidizing fluid flow rates, the removal of oxidationproducts along some or all of the length of the reaction zone, and/orthe distribution of the oxidizing fluid along some or all of the lengthof the reaction zone) may control oxygen diffusion in the reaction zoneand thereby control the reaction rates in the reaction zone.

[1144] In the embodiment shown in FIG. 55, conductor 1112 is placed inopening 544. Conductor 1112 may extend from first end 1114 of opening544 to second end 1116 of opening 544. In certain embodiments, conductor1112 may be placed in opening 544 within hydrocarbon layer 522. One ormore low resistance sections 1118 may be coupled to conductor 1112 andused in overburden 524. In some embodiments, conductor 1112 and/or lowresistance sections 1118 may extend above the surface of the formation.

[1145] In some heat source embodiments, an electric current may beapplied to conductor 1112 to increase a temperature of the conductor.Heat may transfer from conductor 1112 to heated portion 1106 ofhydrocarbon layer 522. Heat may transfer from conductor 1112 to heatedportion 1106 substantially by radiation. Some heat may also transfer byconvection or conduction. Current may be provided to the conductor untila temperature within heated portion 1106 is sufficient to support theoxidation of hydrocarbons within the heated portion. As shown in FIG.55, oxidizing fluid may be provided into conductor 1112 from oxidizingfluid source 1094 at one or both ends 1114, 1116 of opening 544. A flowof the oxidizing fluid from conductor 1112 into opening 544 may becontrolled by orifices 1098. The orifices may be critical flow orifices.The flow of oxidizing fluid from orifices 1098 may be controlled by adiameter of the orifices, a number of orifices, and/or by a pressurewithin conductor 1112 (i.e., a pressure behind the orifices).

[1146] Reaction of oxidizing fluids with hydrocarbons in reaction zone1104 may generate heat. The rate of heat generated in reaction zone 1104may be controlled by a flow rate of the oxidizing fluid into theformation, the rate of diffusion of oxidizing fluid through the reactionzone, and/or a removal rate of oxidation products from the formation. Inan embodiment, oxidation products from the reaction of oxidizing fluidwith hydrocarbons in the formation are removed through one or both endsof opening 544. In some embodiments, a conduit may be placed in opening544 to remove oxidation product. All or portions of the oxidationproducts may be recycled and/or reused in other oxidation type heaters(e.g., natural distributed combustors, surface burners, downholecombustors, etc.). Heat generated in reaction zone 1104 may transfer toa surrounding portion (e.g., selected section) of the formation. Thetransfer of heat between reaction zone 1104 and a selected section maybe substantially by conduction. In certain embodiments, the transferredheat may increase a temperature of the selected section above a minimummobilization temperature of the hydrocarbons and/or a minimum pyrolysistemperature of the hydrocarbons.

[1147] In some heat source embodiments, a conduit may be placed in theopening. The opening may extend through the formation contacting asurface of the earth at a first location and a second location.Oxidizing fluid may be provided to the conduit from the oxidizing fluidsource at the first location and/or the second location after a portionof the formation that has been heated to a temperature sufficient tosupport oxidation of hydrocarbons by the oxidizing fluid.

[1148]FIG. 56 illustrates an embodiment of a section of overburden 524with a natural distributed combustor as described in FIG. 52. Overburdencasing 1120 may be disposed in overburden 524. Overburden casing 1120may be surrounded by materials (e.g., an insulating material such ascement) that inhibit heating of overburden 524. Overburden casing 1120may be made of a metal material such as, but not limited to, carbonsteel or 304 stainless steel.

[1149] Overburden casing 1120 may be placed in reinforcing material 1122in overburden 524. Reinforcing material 1122 may be, but is not limitedto, cement, gravel, sand, and/or concrete. Packing material 1100 may bedisposed between overburden casing 1120 and opening 544 in theformation. Packing material 1100 may be any substantially non-porousmaterial (e.g., cement, concrete, grout, etc.). Packing material 1100may inhibit flow of fluid outside of conduit 1090 and between opening544 and surface 542. Inner conduit 1092 may introduce fluid into opening544 in hydrocarbon layer 522. Conduit 1090 may remove combustion product(or excess oxidation fluid) from opening 544 in hydrocarbon layer 522.Diameter of conduit 1090 may be determined by an amount of thecombustion product produced by oxidation in the natural distributedcombustor. For example, a larger diameter may be required for a greateramount of exhaust product produced by the natural distributed combustorheater.

[1150] In some heat source embodiments, a portion of the formationadjacent to a wellbore may be heated to a temperature and at a heatingrate that converts hydrocarbons to coke or char adjacent to the wellboreby a first heat source. Coke and/or char may be formed at temperaturesabove about 400° C. In the presence of an oxidizing fluid, the coke orchar will oxidize. The wellbore may be used as a natural distributedcombustor subsequent to the formation of coke and/or char. Heat may begenerated from the oxidation of coke or char.

[1151]FIG. 57 illustrates an embodiment of a natural distributedcombustor heater. Insulated conductor 1124 may be coupled to conduit1092 and placed in opening 544 in hydrocarbon layer 522. Insulatedconductor 1124 may be disposed internal to conduit 1092 (therebyallowing retrieval of insulated conductor 1124), or, alternately,coupled to an external surface of conduit 1092. Insulating material forthe conductor may include, but is not limited to, mineral coating and/orceramic coating. Conduit 1092 may have critical flow orifices 1098disposed along its length within opening 544. Electrical current may beapplied to insulated conductor 1124 to generate radiant heat in opening544. Conduit 1092 may serve as a return for current. Insulated conductor1124 may heat portion 1106 of hydrocarbon layer 522 to a temperaturesufficient to support oxidation of hydrocarbons.

[1152] Oxidizing fluid source 1094 may provide oxidizing fluid intoconduit 1092. Oxidizing fluid may be provided into opening 544 throughcritical flow orifices 1098 in conduit 1092. Oxidizing fluid may oxidizeat least a portion of the hydrocarbon layer in reaction zone 1104. Aportion of heat generated at reaction zone 1104 may transfer to selectedsection 1108 by convection, radiation, and/or conduction. Oxidationproducts may be removed through a separate conduit placed in opening 544or through opening 1126 in overburden casing 1120.

[1153]FIG. 58 illustrates an embodiment of a natural distributedcombustor heater with an added fuel conduit. Fuel conduit 1128 may beplaced in opening 544. Fuel conduit 1128 may be placed adjacent toconduit 1092 in certain embodiments. Fuel conduit 1128 may have orifices1130 along a portion of the length within opening 544. Conduit 1092 mayhave orifices 1098 along a portion of the length within opening 544.Fuel conduit may have orifices 1130. In some embodiments, orifices 1130are critical flow orifices. Orifices 1130, 1098 may be positioned sothat a fuel fluid provided through fuel conduit 1128 and an oxidizingfluid provided through conduit 1092 do not react to heat the fuelconduit and the conduit. Heat from reaction of the fuel fluid withoxidizing fluid may heat fuel conduit 1128 and/or conduit 1092 to atemperature sufficient to begin melting metallurgical materials in fuelconduit 1128 and/or conduit 1092 if the reaction takes place proximatefuel conduit 1128 and/or conduit 1092. Orifices 1130 on fuel conduit1128 and orifices 1098 on conduit 1092 may be positioned so that thefuel fluid and the oxidizing fluid do not react proximate the conduits.For example, conduits 1128 and 1092 may be positioned such that orificesthat spiral around the conduits are oriented in opposite directions.

[1154] Reaction of the fuel fluid and the oxidizing fluid may produceheat. In some embodiments, the fuel fluid may be methane, ethane,hydrogen, or synthesis gas that is generated by in situ conversion inanother part of the formation. The produced heat may heat portion 1106to a temperature sufficient to support oxidation of hydrocarbons. Uponheating of portion 1106 to a temperature sufficient to supportoxidation, a flow of fuel fluid into opening 544 may be turned down ormay be turned off. In some embodiments, the supply of fuel may becontinued throughout the heating of the formation.

[1155] The oxidizing fluid may oxidize at least a portion of thehydrocarbons at reaction zone 1104. Generated heat may transfer toselected section 1108 by radiation, convection, and/or conduction. Anoxidation product may be removed through a separate conduit placed inopening 544 or through opening 1126 in overburden casing 1120.

[1156]FIG. 53 illustrates an embodiment of a system that may heat ahydrocarbon containing formation. Electric heater 1132 may be disposedwithin opening 544 in hydrocarbon layer 522. Opening 544 may be formedthrough overburden 524 into hydrocarbon layer 522. Opening 544 may be atleast about 5 cm in diameter. Opening 544 may, as an example, have adiameter of about 13 cm. Electric heater 1132 may heat at least portion1106 of hydrocarbon layer 522 to a temperature sufficient to supportoxidation (e.g., about 260° C.). Portion 1106 may have a width of about1 m. An oxidizing fluid may be provided into the opening through conduit1090 or any other appropriate fluid transfer mechanism. Conduit 1090 mayhave critical flow orifices 1098 disposed along a length of the conduit.

[1157] Conduit 1090 may be a pipe or tube that provides the oxidizingfluid into opening 544 from oxidizing fluid source 1094. In anembodiment, a portion of conduit 1090 that may be exposed to hightemperatures is a stainless steel tube and a portion of the conduit thatwill not be exposed to high temperatures (i.e., a portion of the tubethat extends through the overburden) is carbon steel. The oxidizingfluid may include air or any other oxygen containing fluid (e.g.,hydrogen peroxide, oxides of nitrogen, ozone). Mixtures of oxidizingfluids may be used. An oxidizing fluid mixture may be a fluid includingfifty percent oxygen and fifty percent nitrogen. In some embodiments,the oxidizing fluid may include compounds that release oxygen whenheated, such as hydrogen peroxide. The oxidizing fluid may oxidize atleast a portion of the hydrocarbons in the formation.

[1158]FIG. 59 illustrates an embodiment of a system that heats ahydrocarbon containing formation. Heat exchange unit 1134 may bedisposed external to opening 544 in hydrocarbon layer 522. Opening 544may be formed through overburden 524 into hydrocarbon layer 522. Heatexchange unit 1134 may provide heat from another surface process, or itmay include a heater (e.g., an electric or combustion heater). Oxidizingfluid source 1094 may provide an oxidizing fluid to heat exchange unit1134. Heat exchange unit 1134 may heat an oxidizing fluid (e.g., above200° C. or to a temperature sufficient to support oxidation ofhydrocarbons). The heated oxidizing fluid may be provided into opening544 through conduit 1092. Conduit 1092 may have orifices 1098 disposedalong a length of the conduit. In some embodiments, orifices 1098 may becritical flow orifices. The heated oxidizing fluid may heat, or at leastcontribute to the heating of, at least portion 1106 of the formation toa temperature sufficient to support oxidation of hydrocarbons. Theoxidizing fluid may oxidize at least a portion of the hydrocarbons inthe formation. Opening 1126 may be present to allow for release ofoxidation products from the formation. The oxidation products may besent through a piping system to a treatment facility. After temperaturein the formation is sufficient to support oxidation, use of heatexchange unit 1134 may be reduced or phased out.

[1159] An embodiment of a natural distributed combustor may include asurface combustor (e.g., a flame-ignited heater). A fuel fluid may beoxidized in the combustor. The oxidized fuel fluid may be provided intoan opening in the formation from the heater through a conduit. Oxidationproducts and unreacted fuel may return to the surface through anotherconduit. In some embodiments, one of the conduits may be placed withinthe other conduit. The oxidized fuel fluid may heat, or contribute tothe heating of, a portion of the formation to a temperature sufficientto support oxidation of hydrocarbons. Upon reaching the temperaturesufficient to support oxidation, the oxidized fuel fluid may be replacedwith an oxidizing fluid. The oxidizing fluid may oxidize at least aportion of the hydrocarbons at a reaction zone within the formation.

[1160] An electric heater may heat a portion of the hydrocarboncontaining formation to a temperature sufficient to support oxidation ofhydrocarbons. The portion may be proximate or substantially adjacent tothe opening in the formation. The portion may radially extend a width ofless than approximately 1 m from the opening. An oxidizing fluid may beprovided to the opening for oxidation of hydrocarbons. Oxidation of thehydrocarbons may heat the hydrocarbon containing formation in a processof natural distributed combustion. Electrical current applied to theelectric heater may subsequently be reduced or may be turned off.Natural distributed combustion may be used in conjunction-with anelectric heater to provide a reduced input energy cost method to heatthe hydrocarbon containing formation compared to using only an electricheater.

[1161] An insulated conductor heater may be a heater element of a heatsource. In an embodiment of an insulated conductor heater, the insulatedconductor heater is a mineral insulated cable or rod. An insulatedconductor heater may be placed in an opening in a hydrocarbon containingformation. The insulated conductor heater may be placed in an uncasedopening in the hydrocarbon containing formation. Placing the heater inan uncased opening in the hydrocarbon containing formation may allowheat transfer from the heater to the formation by radiation as well asconduction. Using an uncased opening may facilitate retrieval of theheater from the well, if necessary. Using an uncased opening maysignificantly reduce heat source capital cost by eliminating a need fora portion of casing able to withstand high temperature conditions. Insome heat source embodiments, an insulated conductor heater may beplaced within a casing in the formation; may be cemented within theformation; or may be packed in an opening with sand, gravel, or otherfill material. The insulated conductor heater may be supported on asupport member positioned within the opening. The support member may bea cable, rod, or a conduit (e.g., a pipe). The support member may bemade of a metal, ceramic, inorganic material, or combinations thereof.Portions of a support member may be exposed to formation fluids and heatduring use, so the support member may be chemically resistant andthermally resistant.

[1162] Ties, spot welds, and/or other types of connectors may be used tocouple the insulated conductor heater to the support member at variouslocations along a length of the insulated conductor heater. The supportmember may be attached to a wellhead at an upper surface of theformation. In an embodiment of an insulated conductor heater, theinsulated conductor heater is designed to have sufficient structuralstrength so that a support member is not needed. The insulated conductorheater will in many instances have some flexibility to inhibit thermalexpansion damage when heated or cooled.

[1163] In certain embodiments, insulated conductor heaters may be placedin wellbores without support members and/or centralizers. An insulatedconductor heater without support members and/or centralizers may have asuitable combination of temperature and corrosion resistance, creepstrength, length, thickness (diameter), and metallurgy that will inhibitfailure of the insulated conductor during use. For example, an insulatedconductor without support members that has a working temperature limitof about 700° C. may be less than about 150 m in length and may be madeof 310 stainless steel.

[1164]FIG. 60 depicts a perspective view of an end portion of anembodiment of insulated conductor 1124. An insulated conductor heatermay have any desired cross-sectional shape, such as, but not limited toround (as shown in FIG. 60), triangular, ellipsoidal, rectangular,hexagonal, or irregular shape. An insulated conductor heater may includeconductor 1136, electrical insulation 1138, and sheath 1140. Conductor1136 may resistively heat when an electrical current passes through theconductor. An alternating or direct current may be used to heatconductor 1136. In an embodiment, a 60-cycle AC current is used.

[1165] In some embodiments, electrical insulation 1138 may inhibitcurrent leakage and arcing to sheath 1140. Electrical insulation 1138may also thermally conduct heat generated in conductor 1136 to sheath1140. Sheath 1140 may radiate or conduct heat to the formation.Insulated conductor 1124 may be 1000 m or more in length. In anembodiment of an insulated conductor heater, insulated conductor 1124may have a length from about 15 m to about 950 m. Longer or shorterinsulated conductors may also be used to meet specific applicationneeds. In embodiments of insulated conductor heaters, purchasedinsulated conductor heaters have lengths of about 100 m to 500 m (e.g.,230 m). In certain embodiments, dimensions of sheaths and/or conductorsof an insulated conductor may be selected so that the insulatedconductor has enough strength to be self supporting even at upperworking temperature limits. Such insulated cables may be suspended fromwellheads or supports positioned near an interface between an overburdenand a hydrocarbon containing formation without the need for supportmembers extending into the hydrocarbon containing formation along withthe insulated conductors.

[1166] In an embodiment, a higher frequency current may be used to takeadvantage of the skin effect in certain metals. In some embodiments, a60 cycle AC current may be used in combination with conductors made ofmetals that exhibit pronounced skin effects. For example, ferromagneticmetals like iron alloys and nickel may exhibit a skin effect. The skineffect confines the current to a region close to the outer surface ofthe conductor, thereby effectively increasing the resistance of theconductor. A high resistance may be desired to decrease the operatingcurrent, minimize ohmic losses in surface cables, and minimize the costof treatment facilities.

[1167] Insulated conductor 1124 may be designed to operate at powerlevels of up to about 1650 watts/meter. Insulated conductor 1124 maytypically operate at a power level between about 500 watts/meter andabout 1150 watts/meter when heating a formation. Insulated conductor1124 may be designed so that a maximum voltage level at a typicaloperating temperature does not cause substantial thermal and/orelectrical breakdown of electrical insulation 1138. Insulated conductor1124 may be designed so that sheath 1140 does not exceed a temperaturethat will result in a significant reduction in corrosion resistanceproperties of the sheath material.

[1168] In an embodiment of insulated conductor 1124, conductor 1136 maybe designed to reach temperatures within a range between about 650° C.and about 870° C. The sheath 1140 may be designed to reach temperatureswithin a range between about 535° C. and about 760° C. Insulatedconductors having other operating ranges may be formed to meet specificoperational requirements. In an embodiment of insulated conductor 1124,conductor 1136 is designed to operate at about 760° C., sheath 1140 isdesigned to operate at about 650° C., and the insulated conductor heateris designed to dissipate about 820 watts/meter.

[1169] Insulated conductor 1124 may have one or more conductors 1136.For example, a single insulated conductor heater may have threeconductors within electrical insulation that are surrounded by a sheath.FIG. 60 depicts insulated conductor 1124 having a single conductor 1136.The conductor may be made of metal. The material used to form aconductor may be, but is not limited to, nichrome, nickel, and a numberof alloys made from copper and nickel in increasing nickelconcentrations from pure copper to Alloy 30, Alloy 60, Alloy 180, andMonel. Alloys of copper and nickel may advantageously have betterelectrical resistance properties than substantially pure nickel orcopper.

[1170] In an embodiment, the conductor may be chosen to have a diameterand a resistivity at operating temperatures such that its resistance, asderived from Ohm's law, makes it electrically and structurally stablefor the chosen power dissipation per meter, the length of the heater,and/or the maximum voltage allowed to pass through the conductor. Insome embodiments, the conductor may be designed using Maxwell'sequations to make use of skin effect.

[1171] The conductor may be made of different materials along a lengthof the insulated conductor heater. For example, a first section of theconductor may be made of a material that has a significantly lowerresistance than a second section of the conductor. The first section maybe placed adjacent to a formation layer that does not need to be heatedto as high a temperature as a second formation layer that is adjacent tothe second section. The resistivity of various sections of conductor maybe adjusted by having a variable diameter and/or by having conductorsections made of different materials.

[1172] A diameter of conductor 1136 may typically be between about 1.3mm to about 10.2 mm. Smaller or larger diameters may also be used tohave conductors with desired resistivity characteristics. In anembodiment of an insulated conductor heater, the conductor is made ofAlloy 60 that has a diameter of about 5.8 mm.

[1173] Electrical insulator 1138 of insulated conductor 1124 may be madeof a variety of materials. Pressure may be used to place electricalinsulator powder between conductor 1136 and sheath 1140. Low flowcharacteristics and other properties of the powder and/or the sheathsand conductors may inhibit the powder from flowing out of the sheaths.Commonly used powders may include, but are not limited to, MgO, Al₂O₃,Zirconia, BeO, different chemical variations of Spinels, andcombinations thereof. MgO may provide good thermal conductivity andelectrical insulation properties. The desired electrical insulationproperties include low leakage current and high dielectric strength. Alow leakage current decreases the possibility of thermal breakdown andthe high dielectric strength decreases the possibility of arcing acrossthe insulator. Thermal breakdown can occur if the leakage current causesa progressive rise in the temperature of the insulator leading also toarcing across the insulator. An amount of impurities 1142 in theelectrical insulator powder may be tailored to provide requireddielectric strength and a low level of leakage current. Impurities 1142added may be, but are not limited to, CaO, Fe₂O₃, Al₂O₃, and other metaloxides. Low porosity of the electrical insulation tends to reduceleakage current and increase dielectric strength. Low porosity may beachieved by increased packing of the MgO powder during fabrication or byfilling of the pore space in the MgO powder with other granularmaterials, for example, Al₂O₃.

[1174] Impurities 1142 added to the electrical insulator powder may haveparticle sizes that are smaller than the particle sizes of the powderedelectrical insulator. The small particles may occupy pore space betweenthe larger particles of the electrical insulator so that the porosity ofthe electrical insulator is reduced. Examples of powdered electricalinsulators that may be used to form electrical insulation 1138 are “H”mix manufactured by Idaho Laboratories Corporation (Idaho Falls, Id.) orStandard MgO used by Pyrotenax Cable Company (Trenton, Ontario) for hightemperature applications. In addition, other powdered electricalinsulators may be used.

[1175] Sheath 1140 of insulated conductor 1124 may be an outer metalliclayer. Sheath 1140 may be in contact with hot formation fluids. Sheath1140 may need to be made of a material having a high resistance tocorrosion at elevated temperatures. Alloys that may be used in a desiredoperating temperature range of the sheath include, but are not limitedto, 304 stainless steel, 310 stainless steel, Incoloy 800, and Inconel600. The thickness of the sheath has to be sufficient to last for threeto ten years in a hot and corrosive environment. A thickness of thesheath may generally vary between about 1 mm and about 2.5 mm. Forexample, a 1.3 mm thick, 310 stainless steel outer layer may be used assheath 1140 to provide good chemical resistance to sulfidation corrosionin a heated zone of a formation for a period of over 3 years. Larger orsmaller sheath thicknesses may be used to meet specific applicationrequirements.

[1176] An insulated conductor heater may be tested after fabrication.The insulated conductor heater may be required to withstand 2-3 times anoperating voltage at a selected operating temperature. Also, selectedsamples of produced insulated conductor heaters may be required towithstand 1000 VAC at 760° C. for one month.

[1177] As illustrated in FIG. 62, short flexible transition conductor1144 may be connected to lead-in conductor 1146 using connection 1148made during heater installation in the field. Transition conductor 1144may be a flexible, low resistivity, stranded copper cable that issurrounded by rubber or polymer insulation. Transition conductor 1144may typically be between about 1.5 m and about 3 m, although longer orshorter transition conductors may be used to accommodate particularneeds. Temperature resistant cable may be used as transition conductor1144. Transition conductor 1144 may also be connected to a short lengthof an insulated conductor heater that is less resistive than a primaryheating section of the insulated conductor heater. The less resistiveportion of the insulated conductor heater may be referred to as “coldpin” 1150.

[1178] Cold pin 1150 may be designed to dissipate about one-tenth toabout one-fifth of the power per unit length as is dissipated in a unitlength of the primary heating section. Cold pins may typically bebetween about 1.5 m and about 15 m, although shorter or longer lengthsmay be used to accommodate specific application needs. In an embodiment,the conductor of a cold pin section is copper with a diameter of about6.9 mm and a length of 9.1 m. The electrical insulation is the same typeof insulation used in the primary heating section. A sheath of the coldpin may be made of Inconel 600. Chloride corrosion cracking in the coldpin region may occur, so a chloride corrosion resistant metal such asInconel 600 may be used as the sheath.

[1179] Small, epoxy filled canister 1152 may be used to create aconnection between transition conductor 1144 and cold pin 1150. Coldpins 1150 may be connected to the primary heating sections of insulatedconductor 1124 by “splices” 1154. The length of cold pin 1150 may besufficient to significantly reduce a temperature of insulated conductor1124. The heater section of the insulated conductor 1124 may operatefrom about 530° C. to about 760° C., splice 1154 may be at a temperaturefrom about 260° C. to about 370° C., and the temperature at the lead-incable connection to the cold pin may be from about 40° C. to about 90°C. In addition to a cold pin at a top end of the insulated conductorheater, a cold pin may also be placed at a bottom end of the insulatedconductor heater. The cold pin at the bottom end may in many instancesmake a bottom termination easier to manufacture.

[1180] Splice material may have to withstand a temperature equal to halfof a target zone operating temperature. Density of electrical insulationin the splice should in many instances be high enough to withstand therequired temperature and the operating voltage.

[1181] Splice 1154 may be required to withstand 1000 VAC at 480° C.Splice material may be high temperature splices made by IdahoLaboratories Corporation or by Pyrotenax Cable Company. A splice may bean internal type of splice or an external splice. An internal splice istypically made without welds on the sheath of the insulated conductorheater. The lack of weld on the sheath may avoid potential weak spots(mechanical and/or electrical) on the insulated cable heater. Anexternal splice is a weld made to couple sheaths of two insulatedconductor heaters together. An external splice may need to be leaktested prior to insertion of the insulated cable heater into aformation. Laser welds or orbital TIG (tungsten inert gas) welds may beused to form external splices. An additional strain relief assembly maybe placed around an external splice to improve the splice's resistanceto bending and to protect the external splice against partial or totalparting.

[1182] In certain embodiments, an insulated conductor assembly, such asthe assembly depicted in FIG. 61 and FIG. 62, may have to withstand ahigher operating voltage than normally would be used. For example, forheaters greater than about 700 m in length, voltages greater than about2000 V may be needed for generating heat with the insulated conductor,as compared to voltages of about 480 V that may be used with heatershaving lengths of less than about 225 m. In such cases, it may beadvantageous to form insulated conductor 1124, cold pin 1150, transitionconductor 1144, and lead-in conductor 1146 into a single insulatedconductor assembly. In some embodiments, cold pin 1150 and canister 1152may not be required as shown in FIG. 62. In such an embodiment, splice1154 can be used to directly couple insulated conductor 1124 totransition conductor 1144.

[1183] In a heat source embodiment, insulated conductor 1124, transitionconductor 1144, and lead-in conductor 1146 each include insulatedconductors of varying resistance. Resistance of the conductors may bevaried, for example, by altering a type of conductor, a diameter of aconductor, and/or a length of a conductor. In an embodiment, diametersof insulated conductor 1124, transition conductor 1144, and lead-inconductor 1146 are different. Insulated conductor 1124 may have adiameter of 6 mm, transition conductor 1144 may have a diameter of 7 mm,and lead-in conductor 1146 may have a diameter of 8 mm. Smaller orlarger diameters may be used to accommodate site conditions (e.g.,heating requirements or voltage requirements). Insulated conductor 1124may have a higher resistance than either transition conductor 1144 orlead-in conductor 1146, such that more heat is generated in theinsulated conductor. Also, transition conductor 1144 may have aresistance between a resistance of insulated conductor 1124 and lead-inconductor 1146. Insulated conductor 1124, transition conductor 1144, andlead-in conductor 1146 may be coupled using splice 1154 and/orconnection 1148. Splice 1154 and/or connection 1148 may be required towithstand relatively large operating voltages depending on a length ofinsulated conductor 1124 and/or lead-in conductor 1146. Splice 1154and/or connection 1148 may inhibit arcing and/or voltage breakdownswithin the insulated conductor assembly. Using insulated conductors foreach cable within an insulated conductor assembly may allow for higheroperating voltages within the assembly.

[1184] An insulated conductor assembly may include heating sections,cold pins, splices, termination canisters and flexible transitionconductors. The insulated conductor assembly may need to be examined andelectrically tested before installation of the assembly into an openingin a formation. The assembly may need to be examined for competent weldsand to make sure that there are no holes in the sheath anywhere alongthe whole heater (including the heated section, the cold pins, thesplices, and the termination cans). Periodic X-ray spot checking of thecommercial product may need to be made. The whole cable may be immersedin water prior to electrical testing. Electrical testing of the assemblymay need to show more than 2000 megaohms at 500 VAC at room temperatureafter water immersion. In addition, the assembly may need to beconnected to 1000 VAC and show less than about 10 microamps per meter ofresistive leakage current at room temperature. In addition, a check onleakage current at about 760° C. may need to show less than about 0.4milliamps per meter.

[1185] A number of companies manufacture insulated conductor heaters.Such manufacturers include, but are not limited to, MI CableTechnologies (Calgary, Alberta), Pyrotenax Cable Company (Trenton,Ontario), Idaho Laboratories Corporation (Idaho Falls, Id.), and Watlow(St. Louis, Mo.). As an example, an insulated conductor heater may beordered from Idaho Laboratories as cable model 355-A90-310-“H”30′/750′/30′ with Inconel 600 sheath for the cold pins, three-phase Yconfiguration, and bottom jointed conductors. The specification for theheater may also include 1000 VAC, 1400° F. quality cable. The designator355 specifies the cable OD (0.355″); A90 specifies the conductormaterial; 310 specifies the heated zone sheath alloy (SS 310); “H”specifies the MgO mix; and 30′/750′/30′ specifies about a 230 m heatedzone with cold pins top and bottom having about 9 m lengths. A similarpart number with the same specification using high temperature Standardpurity MgO cable may be ordered from Pyrotenax Cable Company.

[1186] One or more insulated conductor heaters may be placed within anopening in a formation to form a heat source or heat sources. Electricalcurrent may be passed through each insulated conductor heater in theopening to heat the formation. Alternately, electrical current may bepassed through selected insulated conductor heaters in an opening. Theunused conductors may be backup heaters. Insulated conductor heaters maybe electrically coupled to a power source in any convenient manner. Eachend of an insulated conductor heater may be coupled to lead-in cablesthat pass through a wellhead. Such a configuration typically has a 180°bend (a “hairpin” bend) or turn located near a bottom of the heatsource. An insulated conductor heater that includes a 180° bend or turnmay not require a bottom termination, but the 180° bend or turn may bean electrical and/or structural weakness in the heater. Insulatedconductor heaters may be electrically coupled together in series, inparallel, or in series and parallel combinations. In some embodiments ofheat sources, electrical current may pass into the conductor of aninsulated conductor heater and may be returned through the sheath of theinsulated conductor heater by connecting conductor 1136 to sheath 1140(shown in FIG. 60) at the bottom of the heat source.

[1187] In the embodiment of a heat source depicted in FIG. 61, threeinsulated conductors 1124 are electrically coupled in a 3-phase Yconfiguration to a power supply. The power supply may provide 60 cycleAC current to the electrical conductors. No bottom connection may berequired for the insulated conductor heaters. Alternately, all threeconductors of the three-phase circuit may be connected together near thebottom of a heat source opening. The connection may be made directly atends of heating sections of the insulated conductor heaters or at endsof cold pins coupled to the heating sections at the bottom of theinsulated conductor heaters. The bottom connections may be made withinsulator filled and sealed canisters or with epoxy filled canisters.The insulator may be the same composition as the insulator used as theelectrical insulation.

[1188] The three insulated conductor heaters depicted in FIG. 61 may becoupled to support member 1156 using centralizers 1158. Alternatively,the three insulated conductor heaters may be strapped directly to thesupport tube using metal straps. Centralizers 1158 may maintain alocation and/or inhibit movement of insulated conductors 1124 on supportmember 1156. Centralizers 1158 may be made of metal, ceramic, orcombinations thereof. The metal may be stainless steel or any other typeof metal able to withstand a corrosive and hot environment. In someembodiments, centralizers 1158 may be bowed metal strips welded to thesupport member at distances less than about 6 m. A ceramic used incentralizer 1158 may be, but is not limited to, Al₂O₃, MgO, or otherinsulator. Centralizers 1158 may maintain a location of insulatedconductors 1124 on support member 1156 such that movement of insulatedconductor heaters is inhibited at operating temperatures of theinsulated conductor heaters. Insulated conductors 1124 may also besomewhat flexible to withstand expansion of support member 1156 duringheating.

[1189] Support member 1156, insulated conductor 1124, and centralizers1158 may be placed in opening 544 in hydrocarbon layer 522. Insulatedconductors 1124 may be coupled to bottom conductor junction 1160 usingcold pin 1150. Bottom conductor junction 1160 may electrically coupleeach insulated conductor 562 to each other. Bottom conductor junction1160 may include materials that are electrically conducting and do notmelt at temperatures found in opening 544. Cold pin transition conductor1150 may be an insulated conductor heater having lower electricalresistance than insulated conductor 1124. As illustrated in FIG. 62,cold pin 1150 may be coupled to transition conductor 1144 and insulatedconductor 1124. Cold pin transition conductor 1150 may provide atemperature transition between transition conductor 1144 and insulatedconductor 1124.

[1190] Lead-in conductor 1146 may be coupled to wellhead 1162 to provideelectrical power to insulated conductor 1124. Lead-in conductor 1146 maybe made of a relatively low electrical resistance conductor such thatrelatively little heat is generated from electrical current passingthrough lead-in conductor 1146. In some embodiments, the lead-inconductor is a rubber or polymer insulated stranded copper wire. In someembodiments, the lead-in conductor is a mineral-insulated conductor witha copper core. Lead-in conductor 1146 may couple to wellhead 1162 atsurface 542 through a sealing flange located between overburden 524 andsurface 542. The sealing flange may inhibit fluid from escaping fromopening 544 to surface 542.

[1191] Packing material 1100 may be placed between overburden casing1120 and opening 544. In some embodiments, reinforcing material 1122 maysecure overburden casing 1120 to overburden 524. In an embodiment of aheat source, overburden casing is a 7.6 cm (3 inch) diameter carbonsteel, schedule 40 pipe. Packing material 1100 may inhibit fluid fromflowing from opening 544 to surface 542. Reinforcing material 1122 mayinclude, for example, Class G or Class H Portland cement mixed withsilica flour for improved high temperature performance, slag or silicaflour, and/or a mixture thereof (e.g., about 1.58 grams per cubiccentimeter slag/silica flour). In some heat source embodiments,reinforcing material 1122 extends radially a width of from about 5 cm toabout 25 cm. In some embodiments, reinforcing material 1122 may extendradially a width of about 10 cm to about 15 cm.

[1192] In certain embodiments, one or more conduits may be provided tosupply additional components (e.g., nitrogen, carbon dioxide, reducingagents such as gas containing hydrogen, etc.) to formation openings, tobleed off fluids, and/or to control pressure. Formation pressures tendto be highest near heating sources. Providing pressure control equipmentin heat sources may be beneficial. In some embodiments, adding areducing agent proximate the heating source assists in providing a morefavorable pyrolysis environment (e.g., a higher hydrogen partialpressure). Since permeability and porosity tend to increase more quicklyproximate the heating source, it is often optimal to add a reducingagent proximate the heating source so that the reducing agent can moreeasily move into the formation.

[1193] Conduit 1164, depicted in FIG. 61, may be provided to add gasfrom gas source 1166, through valve 1168, and into opening 544. Opening1170 is provided in packing material 1100 to allow gas to pass intoopening 544. Conduit 1164 and valve 1172 may be used at different timesto bleed off pressure and/or control pressure proximate opening 544.Conduit 1164, depicted in FIG. 65, may be provided to add gas from gassource 1166, through valve 1168, and into opening 544. An opening isprovided in reinforcing material 1122 to allow gas to pass into opening544. Conduit 1164 and valve 1172 may be used at different times to bleedoff pressure and/or control pressure proximate opening 544. It is to beunderstood that any of the heating sources described herein may also beequipped with conduits to supply additional components, bleed offfluids, and/or to control pressure.

[1194] As shown in FIG. 61, support member 1156 and lead-in conductor1146 may be coupled to wellhead 1162 at surface 542 of the formation.Surface conductor 1174 may enclose reinforcing material 1122 and coupleto wellhead 1162. Embodiments of surface conductor 1174 may have anouter diameter of about 10.16 cm to about 30.48 cm or, for example, anouter diameter of about 22 cm. Embodiments of surface conductors mayextend to depths of approximately 3 m to approximately 515 m into anopening in the formation. Alternatively, the surface conductor mayextend to a depth of approximately 9 m into the opening. Electricalcurrent may be supplied from a power source to insulated conductor 1124to generate heat due to the electrical resistance of conductor 1136 asillustrated in FIG. 60. As an example, a voltage of about 330 volts anda current of about 266 amps are supplied to insulated conductor 1124 togenerate a heat of about 1150 watts/meter in insulated conductor 1124.Heat generated from the three insulated conductors 1124 may transfer(e.g., by radiation) within opening 544 to heat at least a portion ofthe hydrocarbon layer 522.

[1195]FIG. 63 depicts an embodiment of an insulated conductor heatsource. Insulated conductor 1124 is removable from opening 544 in theformation.

[1196] An appropriate configuration of an insulated conductor heater maybe determined by optimizing a material cost of the heater based on alength of heater, a power required per meter of conductor, and a desiredoperating voltage. In addition, an operating current and voltage may bechosen to optimize the cost of input electrical energy in conjunctionwith a material cost of the insulated conductor heaters. For example, asinput electrical energy increases, the cost of materials needed towithstand the higher voltage may also increase. The insulated conductorheaters may generate radiant heat of approximately 650 watts/meter ofconductor to approximately 1650 watts/meter of conductor. The insulatedconductor heater may operate at a temperature between approximately 530°C. and approximately 760° C. within a formation.

[1197] Heat generated by an insulated conductor heater may heat at leasta portion of a hydrocarbon containing formation. In some embodiments,heat may be transferred to the formation substantially by radiation ofthe generated heat to the formation. Some heat may be transferred byconduction or convection of heat due to gases present in the opening.The opening may be an uncased opening. An uncased opening eliminatescost associated with thermally cementing the heater to the formation,costs associated with a casing, and/or costs of packing a heater withinan opening. In addition, heat transfer by radiation is typically moreefficient than by conduction, so the heaters may be operated at lowertemperatures in an open wellbore. Conductive heat transfer duringinitial operation of a heat source may be enhanced by the addition of agas in the opening. The gas may be maintained at a pressure up to about27 bars absolute. The gas may include, but is not limited to, carbondioxide and/or helium. An insulated conductor heater in an open wellboremay advantageously be free to expand or contract to accommodate thermalexpansion and contraction. An insulated conductor heater mayadvantageously be removable or redeployable from an open wellbore.

[1198] In an embodiment, an insulated conductor heater may be installedor removed using a spooling assembly. More than one spooling assemblymay be used to install both the insulated conductor and a support membersimultaneously. U.S. Pat. No. 4,572,299 issued to Van Egmond et al.,which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. Alternatively, thesupport member may be installed using a coiled tubing unit. Coiledtubing techniques are described in PCT Patent Nos. WO/0043630 andWO/0043631. The heaters may be un-spooled and connected to the supportas the support is inserted into the well. The electric heater and thesupport member may be un-spooled from the spooling assemblies. Spacersmay be coupled to the support member and the heater along a length ofthe support member. Additional spooling assemblies may be used foradditional electric heater elements.

[1199] In an in situ conversion process embodiment, a heater may beinstalled in a substantially horizontal wellbore. Installing a heater ina wellbore (whether vertical or horizontal) may include placing one ormore heaters (e.g., three mineral insulated conductor heaters) within aconduit. FIG. 66 depicts an embodiment of a portion of three insulatedconductor heaters 1124 placed within conduit 1176. Insulated conductorheaters 1124 may be spaced within conduit 1176 using spacers 1178 tolocate the insulated conductor heater within the conduit.

[1200] The conduit may be reeled onto a spool. The spool may be placedon a transporting platform such as a truck bed or other platform thatcan be transported to a site of a wellbore. The conduit may be unreeledfrom the spool at the wellbore and inserted into the wellbore to installthe heater within the wellbore. A welded cap may be placed at an end ofthe coiled conduit. The welded cap may be placed at an end of theconduit that enters the wellbore first. The conduit may allow easyinstallation of the heater into the wellbore. The conduit may alsoprovide support for the heater.

[1201] In some heat source embodiments, coiled tubing installation maybe used to install one or more wellbore elements placed in openings in aformation for an in situ conversion process. For example, a coiledconduit may be used to install other types of wells in a formation. Theother types of wells may be, but are not limited to, monitor wells,freeze wells or portions of freeze wells, dewatering wells or portionsof dewatering wells, outer casings, injection wells or portions ofinjection wells, production wells or portions of production wells, andheat sources or portions of heat sources. Installing one or morewellbore elements using a coiled conduit installation process may beless expensive and faster than using other installation processes.

[1202] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing is available from QualityTubing, Inc. (Houston, Tex.), Precision Tubing (Houston, Tex.), andother manufacturers. Coiled tubing may be available in many sizes anddifferent materials. Sizes of coiled tubing may range from about 2.5 cm(1 inch) to about 15 cm (6 inches). Coiled tubing may be available in avariety of different metals, including carbon steel. Coiled tubing maybe spooled on a large diameter reel. The reel may be carried on a coiledtubing unit. Suitable coiled tubing units are available from Halliburton(Duncan, Okla.), Fleet Cementers, Inc. (Cisco, Tex.), and Coiled TubingSolutions, Inc. (Eastland, Tex.). Coiled tubing may be unwound from thereel, passed through a straightener, and inserted into a wellbore. Awellcap may be attached (e.g., welded) to an end of the coiled tubingbefore inserting the coiled tubing into a well. After insertion, thecoiled tubing may be cut from the coiled tubing on the reel.

[1203] In some embodiments, coiled tubing may be inserted into apreviously cased opening, e.g., if a well is to be used later as aheater well, production well, or monitoring well. Alternately, coiledtubing installed within a wellbore can later be perforated (e.g., with aperforation gun) and used as a production conduit.

[1204] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer conduit with an innerconduit placed in the outer conduit. A production well may include aheater element or heater elements placed within a casing to inhibitcondensation and refluxing of vapor phase production fluids. A freezewell may include a refrigerant input line placed within a casing, or arefrigeration inlet and outlet line. Spacers may be spaced along alength of an element, or elements, positioned within a casing to inhibitthe element, or elements, from contacting walls of the casing.

[1205] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig or workoverrig. In some embodiments of heat sources, production wells, and freezewells, elements may be placed within the casing before the casing iswound onto a reel.

[1206] Some wells may have sealed casings that inhibit fluid flow fromthe formation into the casing. Sealed casings also inhibit fluid flowfrom the casing into the formation. Some casings may be perforated,screened, or have other types of openings that allow fluid to pass intothe casing from the formation, or fluid from the casing to pass into theformation. In some embodiments, portions of wells are open wellboresthat do not include casings.

[1207] In an embodiment, the support member may be installed usingstandard oil field operations and welding different sections of support.Welding may be done by using orbital welding. For example, a firstsection of the support member may be disposed into the well. A secondsection (e.g., of substantially similar length) may be coupled to thefirst section in the well. The second section may be coupled by weldingthe second section to the first section. An orbital welder disposed atthe wellhead may weld the second section to the first section. Thisprocess may be repeated with subsequent sections coupled to previoussections until a support of desired length is within the well.

[1208]FIG. 64 illustrates a cross-sectional view of one embodiment of awellhead coupled to overburden casing 1120. Flange 1180 may be coupledto, or may be a part of, wellhead 1162. Flange 1180 may be formed ofcarbon steel, stainless steel, or any other material. Flange 1180 may besealed with seal 1182. Seal may be an O-ring, gasket, compression seal,or other type of seal. Support member 1156 may be coupled to flange1180. Support member 1156 may support one or more insulated conductorheaters. In an embodiment, support member 1156 is sealed in flange 1180by welds 1184.

[1209] Power conductor 1186 may be coupled to a lead-in cable and/or aninsulated conductor heater. Power conductor 1186 may provide electricalenergy to the insulated conductor heater. Power conductor 1186 may bepositioned through flange 1188. Scaling flange 1188 may be sealed withseal 1182. Power conductor 1186 may be coupled to support member 1156with band 1190. Band 1190 may include a rigid and corrosion resistantmaterial such as stainless steel. Wellhead 1162 may be sealed with weld1184 such that fluids are inhibited from escaping the formation throughwellhead 1162. Lift bolt 1192 may lift wellhead 1162 and support member1156.

[1210] Thermocouple 1194 may be provided through flange 1180.Thermocouple 1194 may measure a temperature on or proximate supportmember 1156 within the heated portion of the well. Compression fittings1196 may serve to seal power cable 1186. Compression fittings 1196 mayalso be used to seal thermocouple 1194. The compression fittings mayinhibit fluids from escaping the formation. Wellhead 1162 may alsoinclude a pressure control valve. The pressure control valve may controlpressure within an opening in which support member 1156 is disposed.

[1211] In a heat source embodiment, a control system may controlelectrical power supplied to an insulated conductor heater. Powersupplied to the insulated conductor heater may be controlled with anyappropriate type of controller. For alternating current, the controllermay be, but is not limited to, a tapped transformer or a zero crossoverelectric heater firing SCR (silicon controlled rectifier) controller.Zero crossover electric heater firing control may be achieved byallowing full supply voltage to the insulated conductor heater to passthrough the insulated conductor heater for a specific number of cycles,starting at the “crossover,” where an instantaneous voltage may be zero,continuing for a specific number of complete cycles, and discontinuingwhen the instantaneous voltage again crosses zero. A specific number ofcycles may be blocked, allowing control of the heat output by theinsulated conductor heater. For example, the control system may bearranged to block fifteen and/or twenty cycles out of each sixty cyclesthat are supplied by a standard 60 Hz alternating current power supply.Zero crossover firing control may be advantageously used with materialshaving low temperature coefficient materials. Zero crossover firingcontrol may inhibit current spikes from occurring in an insulatedconductor heater.

[1212]FIG. 65 illustrates an embodiment of a conductor-in-conduit heaterthat may heat a hydrocarbon containing formation. Conductor 1112 may bedisposed in conduit 1176. Conductor 1112 may be a rod or conduit ofelectrically conductive material. Low resistance sections 1118 may bepresent at both ends of conductor 1112 to generate less heating in thesesections. Low resistance section 1118 may be formed by having a greatercross-sectional area of conductor 1112 in that section, or the sectionsmay be made of material having less resistance. In certain embodiments,low resistance section 1118 includes a low resistance conductor coupledto conductor 1112. In some heat source embodiments, conductors 1112 maybe 316, 304, or 310 stainless steel rods with diameters of approximately2.8 cm. In some heat source embodiments, conductors are 316, 304, or 310stainless steel pipes with diameters of approximately 2.5 cm. Larger orsmaller diameters of rods or pipes may be used to achieve desiredheating of a formation. The diameter and/or wall thickness of conductor1112 may be varied along a length of the conductor to establishdifferent heating rates at various portions of the conductor.

[1213] Conduit 1176 may be made of an electrically conductive material.For example, conduit 1176 may be a 7.6 cm, schedule 40 pipe made of 316,304, or 310 stainless steel. Conduit 1176 may be disposed in opening 544in hydrocarbon layer 522. Opening 544 has a diameter able to accommodateconduit 1176. A diameter of the opening may be from about 10 cm to about13 cm. Larger or smaller diameter openings may be used to accommodateparticular conduits or designs.

[1214] Conductor 1112 may be centered in conduit 1176 by centralizer1198. Centralizer 1198 may electrically isolate conductor 1112 fromconduit 1176. Centralizer 1198 may inhibit movement and properly locateconductor 1112 within conduit 1176. Centralizer 1198 may be made of aceramic material or a combination of ceramic and metallic materials.Centralizers 1198 may inhibit deformation of conductor 1112 in conduit1176. Centralizer 1198 may be spaced at intervals between approximately0.5 m and approximately 3 m along conductor 1112. FIGS. 67, 68, and 69depict embodiments of centralizers 1198.

[1215] A second low resistance section 1118 of conductor 1112 may coupleconductor 1112 to wellhead 1162, as depicted in FIG. 65. Electricalcurrent may be applied to conductor 1112 from power cable 1200 throughlow resistance section 1118 of conductor 1112. Electrical current maypass from conductor 1112 through sliding connector 1202 to conduit 1176.Conduit 1176 may be electrically insulated from overburden casing 1120and from wellhead 1162 to return electrical current to power cable 1200.Heat may be generated in conductor 1112 and conduit 1176. The generatedheat may radiate within conduit 1176 and opening 544 to heat at least aportion of hydrocarbon layer 522. As an example, a voltage of about 330volts and a current of about 795 amps may be supplied to conductor 1112and conduit 1176 in a 229 m (750 ft) heated section to generate about1150 watts/meter of conductor 1112 and conduit 1176.

[1216] Overburden casing 1120 may be disposed in overburden 524.Overburden casing 1120 may, in some embodiments, be surrounded bymaterials that inhibit heating of overburden 524. Low resistance section1118 of conductor 1112 may be placed in overburden casing 1120. Lowresistance section 1118 of conductor 1112 may be made of, for example,carbon steel. Low resistance section 1118 may have a diameter betweenabout 2 cm to about 5 cm or, for example, a diameter of about 4 cm. Lowresistance section 1118 of conductor 1112 may be centralized withinoverburden casing 1120 using centralizers 1198. Centralizers 1198 may bespaced at intervals of approximately 6 m to approximately 12 m or, forexample, approximately 9 m along low resistance section 1118 ofconductor 1112. In a heat source embodiment, low resistance section 1118of conductor 1112 is coupled to conductor 1112 by a weld or welds. Inother heat source embodiments, low resistance sections may be threaded,threaded and welded, or otherwise coupled to the conductor. Lowresistance section 1118 may generate little and/or no heat in overburdencasing 1120. Packing material 1100 may be placed between overburdencasing 1120 and opening 544. Packing material 1100 may inhibit fluidfrom flowing from opening 544 to surface 542.

[1217] In a heat source embodiment, overburden conduit is a 7.6 cmschedule 40 carbon steel pipe. In some embodiments, the overburdenconduit may be cemented in the overburden. Reinforcing material 1122 maybe slag or silica flour or a mixture thereof (e.g., about 1.58 grams percubic centimeter slag/silica flour). Reinforcing material 1122 mayextend radially a width of about 5 cm to about 25 cm. Reinforcingmaterial 1122 may also be made of material designed to inhibit flow ofheat into overburden 524. In other heat source embodiments, overburdenmay not be cemented into the formation. Having an uncemented overburdencasing may facilitate removal of conduit 1176 if the need for removalshould arise.

[1218] Surface conductor 1174 may couple to wellhead 1162. Surfaceconductor 1174 may have a diameter of about 10 cm to about 30 cm or, incertain embodiments, a diameter of about 22 cm. Electrically insulatingsealing flanges may mechanically couple low resistance section 1118 ofconductor 1112 to wellhead 1162 and to electrically couple lowresistance section 1118 to power cable 1200. The electrically insulatingsealing flanges may couple power cable 1200 to wellhead 1162. Forexample, power cable 1200 may be a copper cable, wire, or otherelongated member. Power cable 1200 may include any material having asubstantially low resistance. The power cable may be clamped to thebottom of the low resistance conductor to make electrical contact.

[1219] In an embodiment, heat may be generated in or by conduit 1176.About 10% to about 30%, or, for example, about 20%, of the total heatgenerated by the heater may be generated in or by conduit 1176. Bothconductor 1112 and conduit 1176 may be made of stainless steel.Dimensions of conductor 1112 and conduit 1176 may be chosen such thatthe conductor will dissipate heat in a range from approximately 650watts per meter to 1650 watts per meter. A temperature in conduit 1176may be approximately 480° C. to approximately 815° C., and a temperaturein conductor 1112 may be approximately 500° C. to 840° C. Substantiallyuniform heating of a hydrocarbon containing formation may be providedalong a length of conduit 1176 greater than about 300 m or even greaterthan about 600 m.

[1220]FIG. 70 depicts a cross-sectional representation of an embodimentof a removable conductor-in-conduit heat source. Conduit 1176 may beplaced in opening 544 through overburden 524 such that a gap remainsbetween the conduit and overburden casing 1120. Fluids may be removedfrom opening 544 through the gap between conduit 1176 and overburdencasing 1120. Fluids may be removed from the gap through conduit 1164.Conduit 1176 and components of the heat source included within theconduit that are coupled to wellhead 1162 may be removed from opening544 as a single unit. The heat source may be removed as a single unit tobe repaired, replaced, and/or used in another portion of the formation.

[1221] In certain embodiments, portions of a conductor-in-conduit heatsource may be moved or removed to adjust a portion of the formation thatis heated by the heat source. For example, in a horizontal well theconductor-in-conduit heat source may be initially almost as long as theopening in the formation. As products are produced from the formation,the conductor-in-conduit heat source may be moved so that it is placedat location further from the end of the opening in the formation. Heatmay be applied to a different portion of the formation by adjusting thelocation of the heat source. In certain embodiments, an end of theheater may be coupled to a sealing mechanism (e.g., a packing mechanism,or a plugging mechanism) to seal off perforations in a liner or casing.The sealing mechanism may inhibit undesired fluid production fromportions of the heat source wellbore from which the conductor-in-conduitheat source has been removed.

[1222] As depicted in FIG. 71, sliding connector 1202 may be couplednear an end of conductor 1112. Sliding connector 1202 may be positionednear a bottom end of conduit 1176. Sliding connector 1202 mayelectrically couple conductor 1112 to conduit 1176. Sliding connector1202 may move during use to accommodate thermal expansion and/orcontraction of conductor 1112 and conduit 1176 relative to each other.In some embodiments, sliding connector 1202 may be attached to lowresistance section 1118 of conductor 1112. The lower resistance of lowresistance section 1118 may allow the sliding connector to be at atemperature that does not exceed about 90° C. Maintaining slidingconnector 1202 at a relatively low temperature may inhibit corrosion ofthe sliding connector and promote good contact between the slidingconnector and conduit 1176.

[1223] Sliding connector 1202 may include scraper 1204. Scraper 1204 mayabut an inner surface of conduit 1176 at point 1206. Scraper 1204 mayinclude any metal or electrically conducting material (e.g., steel orstainless steel). Centralizer 1208 may couple to conductor 1112. In someembodiments, sliding connector 1202 may be positioned on low resistancesection 1118 of conductor 1112. Centralizer 1208 may include anyelectrically conducting material (e.g., a metal or metal alloy). Springbow 1210 may couple scraper 1204 to centralizer 1208. Spring bow 1210may include any metal or electrically conducting material (e.g.,copper-beryllium alloy). In some embodiments, centralizer 1208, springbow 1210, and/or scraper 1204 are welded together.

[1224] More than one sliding connector 1202 may be used for redundancyand to reduce the current through each scraper 1204. In addition, athickness of conduit 1176 may be increased for a length adjacent tosliding connector 1202 to reduce heat generated in that portion ofconduit. The length of conduit 1176 with increased thickness may be, forexample, approximately 6 m.

[1225]FIG. 72 illustrates an embodiment of wellhead 1162. Wellhead 1162may be coupled to electrical junction box 1212 by flange 1214 or anyother suitable mechanical device. Electrical junction box 1212 maycontrol power (current and voltage) supplied to an electric heater.Power source 1216 may be included in electrical junction box 1212. In aheat source embodiment, the electric heater is a conductor-in-conduitheater. Flange 1214 may include, stainless steel or any other suitablesealing material. Conductor 1218 may electrically couple conduit 1176 topower source 1216. In some embodiments, power source 1216 may be locatedoutside wellhead 1162 and the power source is coupled to the wellheadwith power cable 1200, as shown in FIG. 65. Low resistance section 1118may be coupled to power source 1216. Compression fitting 1196 may sealconductor 1218 at an inner surface of electrical junction box 1212.

[1226] Flange 1214 may be sealed with seal 1182. In some embodiments,seal 1182 may be a metal o-ring. Conduit 1220 may couple flange 1214 toflange 1222. Flange 1222 may couple to an overburden casing. Flange 1222may be sealed with seal 1182 (e.g., metal o-ring or steel o-ring). Lowresistance section 1118 of the conductor may couple to electricaljunction box 1212. Low resistance section 1118 may be passed throughflange 1214. Low resistance section 1118 may be sealed in flange 1214with seal assembly 1224. Assemblies 1224 are designed to insulate lowresistance section 1118 from flange 1214 and flange 1222. Seals 1182 maybe designed to electrically insulate conductor 1218 from flange 1214 andjunction box 1212. Centralizer 1198 may couple to low resistance section1118. Thermocouples 1194 may be coupled to thermocouple flange 1226 withconnectors 1228 and wire 1230. Thermocouples 1194 may be enclosed in anelectrically insulated sheath (e.g., a metal sheath). Thermocouples 1194may be sealed in thermocouple flange 1226 with compression fittings1196. Thermocouples 1194 may be used to monitor temperatures in theheated portion downhole. In some embodiments, fluids (e.g., vapors) maybe removed through wellhead 1162. For example, fluids from outsideconduit 1176 may be removed through flange 1232A or fluids within theconduit may be removed through flange 1232B.

[1227]FIG. 73 illustrates an embodiment of a conductor-in-conduit heaterplaced substantially horizontally within hydrocarbon layer 522. Heatedsection 1234 may be placed substantially horizontally within hydrocarbonlayer 522. Heater casing 1236-may be placed within hydrocarbon layer522. Heater casing 1236 may be formed of a corrosion resistant,relatively rigid material (e.g., 304 stainless steel). Heater casing1236 may be coupled to overburden casing 1120. Overburden casing 1120may include materials such as carbon steel. In an embodiment, overburdencasing 1120 and heater casing 1236 have a diameter of about 15 cm.Expansion mechanism 1238 may be placed at an end of heater casing 1236to accommodate thermal expansion of the conduit during heating and/orcooling.

[1228] To install heater casing 1236 substantially horizontally withinhydrocarbon layer 522, overburden casing 1120 may bend from a verticaldirection in overburden 524 into a horizontal direction withinhydrocarbon layer 522. A curved wellbore may be formed during drillingof the wellbore in the formation. Heater casing 1236 and overburdencasing 1120 may be installed in the curved wellbore. A radius ofcurvature of the curved wellbore may be determined by properties ofdrilling in the overburden and the formation. For example, the radius ofcurvature may be about 200 m from point 1240 to point 1242.

[1229] Conduit 1176 may be placed within heater casing 1236. In someembodiments, conduit 1176 may be made of a corrosion resistant metal(e.g., 304 stainless steel). Conduit 1176 may be heated to a hightemperature. Conduit 1176 may also be exposed to hot formation fluids.Conduit 1176 may be treated to have a high emissivity. Conduit 1176 mayhave upper section 1244. In some embodiments, upper section 1244 may bemade of a less corrosion resistant metal than other portions of conduit1176 (e.g., carbon steel). A large portion of upper section 1244 may bepositioned in overburden 524 of the formation. Upper section 1244 maynot be exposed to temperatures as high as the temperatures of conduit1176. In an embodiment, conduit 1176 and upper section 1244 have adiameter of about 7.6 cm.

[1230] Conductor 1112 may be placed in conduit 1176. A portion of theconduit placed adjacent to conductor 1112 may be made of a metal thathas desired electrical properties, emissivity, creep resistance, andcorrosion resistance at high temperatures. Conductor 1112 may include,but is not limited to, 310 stainless steel, 304 stainless steel, 316stainless steel, 347 stainless steel, and/or other steel or non-steelalloys. Conductor 1112 may have a diameter of about 3 cm, however, adiameter of conductor 1112 may vary depending on, but not limited to,heating requirements and power requirements. Conductor 1112 may belocated in conduit 1176 using one or more centralizers 1198.Centralizers 1198 may be ceramic or a combination of metal and ceramic.Centralizers 1198 may inhibit conductor 1112 from contacting conduit1176. In some embodiments, centralizers 1198 may be coupled to conductor1112. In other embodiments, centralizers 1198 may be coupled to conduit1176. Conductor 1112 may be electrically coupled to conduit 1176 usingsliding connector 1202.

[1231] Conductor 1112 may be coupled to transition conductor 1246.Transition conductor 1246 may be used as an electrical transitionbetween lead-in conductor 1146 and conductor 1112. In an embodiment,transition conductor 1246 may be carbon steel. Transition conductor 1246may be coupled to lead-in conductor 1146 with electrical connector 1248.FIG. 74 illustrates an enlarged view of an embodiment of a junction oftransition conductor 1246, electrical connector 1248, insulator 1250,and lead-in conductor 1146. Lead-in conductor 1146 may include one ormore conductors (e.g., three conductors). In certain embodiments, theone or more conductors may be insulated copper conductors (e.g.,rubber-insulated copper cable). In some embodiments, the one or moreconductors may be insulated or un-insulated stranded copper cable.Insulator 1250 may be placed inside lead-in conductor 1146. Insulator1250 may include electrically insulating materials such as fiberglass.

[1232] As depicted in FIG. 73, insulator 1250 may couple electricalconnector 1248 to heater support 1252. In an embodiment, electricalcurrent may flow from a power supply through lead-in conductor 1146,through transition conductor 1246, into conductor 1112, and returnthrough conduit 1176 and upper section 1244.

[1233] Heater support 1252 may include a support that is used to installheated section 1234 in hydrocarbon layer 522. For example, heatersupport 1252 may be a sucker rod that is inserted through overburden 524from a ground surface. The sucker rod may include one or more portionsthat can be coupled to each other at the surface as the rod is insertedinto the formation. In some embodiments, heater support 1252 is a singlepiece assembled in an assembly facility. Inserting heater support 1252into the formation may push heated section 1234 into the formation.

[1234] Overburden casing 1120 may be supported within overburden 524using reinforcing material 1122. Reinforcing material may include cement(e.g., Portland cement). Surface conductor 1174 may enclose reinforcingmaterial 1122 and overburden casing 1120 in a portion of overburden 524proximate the ground surface. Surface conductor 1174 may include asurface casing.

[1235]FIG. 75 illustrates a schematic of an embodiment of aconductor-in-conduit heater placed substantially horizontally within aformation. In an embodiment, heater support 1252 may be a low resistanceconductor (e.g., low resistance section 1118 as shown in FIG. 65).Heater support 1252 may include carbon steel or otherelectrically-conducting materials. Heater support 1252 may beelectrically coupled to transition conductor 1246 and conductor 1112.

[1236] In some embodiments, a heat source may be placed within anuncased wellbore in a hydrocarbon containing formation. FIG. 77illustrates a schematic of an embodiment of a conductor-in-conduitheater placed substantially horizontally within an uncased wellbore in aformation. Heated section 1234 may be placed within opening 544 inhydrocarbon layer 522. In certain embodiments, heater support 1252 maybe a low resistance conductor (e.g., low resistance section 1118 asshown in FIG. 65). Heater support 1252 may be electrically coupled totransition conductor 1246 and conductor 1112. FIG. 76 depicts anembodiment of the conductor-in-conduit heater shown in FIG. 77. Incertain embodiments, perforated casing 1254 may be placed in opening 544as shown in FIG. 76. In some embodiments, centralizers 1198 may be usedto support perforated casing 1254 within opening 544.

[1237] In certain heat source embodiments, a cladding section may becoupled to heater support 1252 and/or upper section 1244. FIG. 78depicts an embodiment of cladding section 1256 coupled to heater support1252. Cladding may also be coupled to an upper section of conduit 1176.Cladding section 1256 may reduce the electrical resistance of heatersupport 1252 and/or the upper section of conduit 1176. In an embodiment,cladding section 1256 is copper tubing coupled to the heater support andthe conduit.

[1238] In other heat source embodiments, heated section 1234, as shownin FIGS. 73, 75, and 77, may be placed in a wellbore with an orientationother than substantially horizontally in hydrocarbon layer 522. Forexample, heated section 1234 may be placed in hydrocarbon layer 522 atan angle of about 45° or substantially vertically in the formation. Inaddition, elements of the heat source placed in overburden 524 (e.g.,heater support 1252, overburden casing 1120, upper section 1244, etc.)may have an orientation other than substantially vertical within theoverburden.

[1239] In certain heat source embodiments, the heat source may beremovably installed in a formation. Heater support 1252 may be used toinstall and/or remove the heat source, including heated section 1234,from the formation. The heat source may be removed to repair, replace,and/or use the heat source in a different wellbore. The heat source maybe reused in the same formation or in a different formation. In someembodiments, a heat source or a portion of a heat source may be spooledon a coiled tubing rig and moved to another well location.

[1240] In some embodiments for heating a hydrocarbon containingformation, more than one heater may be installed in a wellbore or heaterwell. Having more than one heater in a wellbore or heat source mayprovide the ability to heat a selected portion or portions of aformation at a different rate than other portions of the formation.Having more than one heater in a wellbore or heat source may provide abackup heat source in the wellbore or heat source should one or more ofthe heaters fail. Having more than one heater may allow a uniformtemperature profile to be established along a desired portion of thewellbore. Having more than one heater may allow for rapid heating of ahydrocarbon layer or layers to a pyrolysis temperature from ambienttemperature. The more than one heater may include similar types ofheaters or may include different types of heaters. For example, the morethan one heater may be a natural distributed combustor heater, aninsulated conductor heater, a conductor-in-conduit heater, an elongatedmember heater, a downhole combustor (e.g., a downhole flamelesscombustor or a downhole combustor), etc.

[1241] In an in situ conversion process embodiment, a first heater in awellbore may be used to selectively heat a first portion of a formationand a second heater may be used to selectively heat a second portion ofthe formation. The first heater and the second heater may beindependently controlled. For example, heat provided by a first heatercan be controlled separately from heat provided by a second heater. Asanother example, electrical power supplied to a first electric heatermay be controlled independently of electrical power supplied to a secondelectric heater. The first portion and the second portion may be locatedat different heights or levels within a wellbore, either vertically oralong a face of the wellbore. The first portion and the second portionmay be separated by a third, or separate, portion of a formation. Thethird portion may contain hydrocarbons or may be a non-hydrocarboncontaining portion of the formation. For example, the third portion mayinclude rock or similar non-hydrocarbon containing materials. The thirdportion may be heated or unheated. In some embodiments, heat used toheat the first and second portions may be used to heat the thirdportion. Heat provided to the first and second portions maysubstantially uniformly heat the first, second, and third portions.

[1242]FIG. 67 illustrates a perspective view of an embodiment ofcentralizer 1198 in conduit 1176. Electrical insulator 1258 may bedisposed on conductor 1112. Insulator 1258 may be made of aluminum oxideor other electrically insulating material that has a high workingtemperature limit. Neck portion 1260 may be a bushing which has aninside diameter that allows conductor 1112 to pass through the bushing.Neck portion 1260 may include electrically insulative materials such asmetal oxides and ceramics (e.g., aluminum oxide). Insulator 1258 andneck portion 1260 may be obtainable from manufacturers such as CoorsTek(Golden, Colo.) or Norton Ceramics (United Kingdom). In an embodiment,insulator 1258 and/or neck portion 1260 are made from 99% or greaterpurity machinable aluminum oxide. In certain embodiments, ceramicportions of a heat source may be surface glazed. Surface glazing ceramicmay seal the ceramic from contamination from dirt and/or moisture. Hightemperature surface glazing of ceramics may be done by companies such asNGK-Locke Inc. (Baltimore, Md.) or Johannes Gebhart (Germany).

[1243] A location of insulator 1258 on conductor 1112 may be maintainedby disc 1262. Disc 1262 may be welded to conductor 1112. Spring bow 1264may be coupled to insulator 1258 by disc 1266. Spring bow 1264 and disc1266 may be made of metals such as 310 stainless steel and/or any otherthermally conducting material that may be used at relatively hightemperatures. Spring bow 1264 may reduce the stress on ceramic portionsof the centralizer during installation or removal of the heater, and/orduring use of the heater. Reducing the stress on ceramic portions of thecentralizer during installation or removal may increase an operationallifetime of the heater. In some heat source embodiments, centralizer1198 may have an opening that fits over an end of conductor 1112. Inother embodiments, centralizer 1198 may be assembled from two or morepieces around a portion of conductor 1112. The pieces may be coupled toconductor 1112 by fastening device 1268. Fastening device 1268 may bemade of any material that can be used at relatively high temperatures(e.g., steel).

[1244]FIG. 68 depicts a representation of an embodiment of centralizer1198 disposed on conductor 1112. Discs 1262 may maintain positions ofcentralizer 1198 relative to conductor 1112. Discs 1262 may be metaldiscs welded to conductor 1112. Discs 1262 may be tack-welded toconductor 1112. FIG. 69 depicts a top view representation of acentralizer embodiment. Centralizer 1198 may be made of any suitableelectrically insulating material able to withstand high voltage at hightemperatures. Examples of such materials include, but are not limitedto, aluminum oxide and/or Macor. Centralizer 1198 may electricallyinsulate conductor 1112 from conduit 1176, as shown in FIGS. 68 and 69.

[1245]FIG. 79 illustrates a cross-sectional representation of anembodiment of a centralizer placed on a conductor. FIG. 80 depicts aportion of an embodiment of a conductor-in-conduit heat source with acutout view showing a centralizer on the conductor. Centralizer 1198 maybe used in a conductor-in-conduit heat source. Centralizer 1198 may beused to maintain a location of conductor 1112 within conduit 1176.Centralizer 1198 may include electrically insulating materials such asceramics (e.g., alumina and zirconia). As shown in FIG. 79, centralizer1198 may have at least one recess 1270. Recess 1270 may be, for example,an indentation or notch in centralizer 1198 or a recess left by aportion removed from the centralizer. A cross-sectional shape of recess1270 may be a rectangular shape or any other geometrical shape. Incertain embodiments, recess 1270 has a shape that allows protrusion 1272to reside within the recess. Recess 1270 may be formed such that therecess will be placed at a junction of centralizer 1198 and conductor1112. In one embodiment, recess 1270 is formed at a bottom ofcentralizer 1198.

[1246] At least one protrusion 1272 may be formed on conductor 1112.Protrusion 1272 may be welded to conductor 1112. In some embodiments,protrusion 1272 is a weld bead formed on conductor 1112. Protrusion 1272may include electrically-conductive materials such as steel (e.g.,stainless steel). In certain embodiments, protrusion 1272 may includeone or more protrusions formed around the circumference of conductor1112. Protrusion 1272 may be used to maintain a location of centralizer1198 on conductor 1112. For example, protrusion 1272 may inhibitdownward movement of centralizer 1198 along conductor 1112. In someembodiments, at least one additional recess 1270 and at least oneadditional protrusion 1272 may be placed at a top of centralizer 1198 toinhibit upward movement of the centralizer along conductor 1112.

[1247] In an embodiment, electrically insulating material 1274 is placedover protrusion 1272 and recess 1270. Electrically insulating material1274 may cover recess 1270 such that protrusion 1272 is enclosed withinthe recess and the electrically insulating material. In someembodiments, electrically insulating material 1274 may partially coverrecess 1270. Protrusion 1272 may be enclosed so that carbon deposition(i.e., coking) on protrusion 1272 during use is inhibited. Carbon mayform electrically-conducting paths during use of conductor 1112 andconduit 1176 to heat a formation. Electrically insulating material 1274may include materials such as, but not limited to, metal oxides and/orceramics (e.g., alumina or zirconia). In some embodiments, electricallyinsulating material 1274 is a thermally conducting material. A thermalplasma spray process may be used to place electrically insulatingmaterial 1274 over protrusion 1272 and recess 1270. The thermal plasmaprocess may spray coat electrically insulating material 1274 onprotrusion 1272 and/or centralizer 1198.

[1248] In an embodiment, centralizer 1198 with recess 1270, protrusion1272, and electrically insulating material 1274 are placed on conductor1112 within conduit 1176 during installation of the conductor-in-conduitheat source in an opening in a formation. In another embodiment,centralizer 1198 with recess 1270, protrusion 1272, and electricallyinsulating material 1274 are placed on conductor 1112 within conduit1176 during assembling of the conductor-in-conduit heat source. Forexample, an assembling process may include forming protrusion 1272 onconductor 1112, placing centralizer 1198 with recess 1270 on conductor1112, covering the protrusion and the recess with electricallyinsulating material 1274, and placing the conductor within conduit 1176.

[1249]FIG. 81 depicts an embodiment of centralizer 1198. Neck portion1260 may be coupled to centralizer 1198. In certain embodiments, neckportion 1260 is an extended portion of centralizer 1198. Protrusion 1272may be placed on conductor 1112 to maintain a location of centralizer1198 and neck portion 1260 on the conductor. Neck portion 1260 may be abushing which has an inside diameter that allows conductor 1112 to passthrough the bushing. Neck portion 1260 may include electricallyinsulative materials such as metal oxides and ceramics (e.g., aluminumoxide). For example, neck portion 1260 may be a commercially availablebushing from manufacturers such as Borges Technical Ceramics (Pennsburg,Pa.). In one embodiment, as shown in FIG. 81, a first neck portion 1260is coupled to an upper portion of centralizer 1198 and a second neckportion 1260 is coupled to a lower portion of centralizer 1198.

[1250] Neck portion 1260 may extend between about 1 cm and about 5 cmfrom centralizer 1198. In an embodiment, neck portion 1260 extends about2-3 cm from centralizer 1198. Neck portion 1260 may extend a selecteddistance from centralizer 1198 such that arcing (e.g., surface arcing)is inhibited. Neck portion 1260 may increase a path length for arcingbetween conductor 1112 and conduit 1176. A path for arcing betweenconductor 1112 and conduit 1176 may be formed by carbon deposition oncentralizer 1198 and/or neck portion 1260. Increasing the path lengthfor arcing between conductor 1112 and conduit 1176 may reduce thelikelihood of arcing between the conductor and the conduit. Anotheradvantage of increasing the path length for arcing between conductor1112 and conduit 1176 may be an increase in a maximum operating voltageof the conductor.

[1251] In an embodiment, neck portion 1260 also includes one or moregrooves 1276. One or more grooves 1276 may further increase the pathlength for arcing between conductor 1112 and conduit 1176. In certainembodiments, conductor 1112 and conduit 1176 may be orientedsubstantially vertically within a formation. In such an embodiment, oneor more grooves 1276 may also inhibit deposition of conducting particles(e.g., carbon particles or corrosion scale) along the length of neckportion 1260. Conducting particles may fall by gravity along a length ofconductor 1112. One or more grooves 1276 may be oriented such thatfalling particles do not deposit into the one or more grooves.Inhibiting the deposition of conducting particles on neck portion 1260may inhibit formation of an arcing path between conductor 1112 andconduit 1176. In some embodiments, diameters of each of one or moregrooves 1276 may be varied. Varying the diameters of the grooves mayfurther inhibit the likelihood of arcing between conductor 1112 andconduit 1176.

[1252]FIG. 82 depicts an embodiment of centralizer 1198. Centralizer1198 may include two or more portions held together by fastening device1268. Fastening device 1268 may be a clamp, bolt, snap-lock, or screw.FIGS. 83 and 84 depict top views of embodiments of centralizer 1198placed on conductor 1112. Centralizer 1198 may include two portions. Thetwo portions may be coupled together to form a centralizer in a “clamshell” configuration. The two portions may have notches and recessesthat are shaped to fit together as shown in either of FIGS. 83 and 84.In some embodiments, the two portions may have notches and recesses thatare tapered so that the two portions tightly couple together. The twoportions may be slid together lengthwise along the notches and recesses.

[1253] In a heat source embodiment, an insulation layer may be placedbetween a conductor and a conduit. The insulation layer may be used toelectrically insulate the conductor from the conduit. The insulationlayer may also maintain a location of the conductor within the conduit.In some embodiments, the insulation layer may include a layer thatremains placed on and/or in the heat source after installation. Incertain embodiments, the insulation layer may be removed by heating theheat source to a selected temperature. The insulation layer may includeelectrically insulating materials such as, but not limited to, metaloxides and/or ceramics. For example, the insulation layer may be Nextel™insulation obtainable from 3M Company (St. Paul, Minn.). An insulationlayer may also be used for installation of any other heat source (e.g.,insulated conductor heat source, natural distributed combustor, etc.).In an embodiment, the insulation layer is fastened to the conductor. Theinsulation layer may be fastened to the conductor with a hightemperature adhesive (e.g., a ceramic adhesive such as Cotronics 920alumina-based adhesive available from Cotronics Corporation (Brooklyn,N.Y.)).

[1254]FIG. 85 depicts a cross-sectional representation of an embodimentof a section of a conductor-in-conduit heat source with insulation layer1278. Insulation layer 1278 may be placed on conductor 1112. Insulationlayer 1278 may be spiraled around conductor 1112 as shown in FIG. 85. Inone embodiment, insulation layer 1278 is a single insulation layer woundaround the length of conductor 1112. In some embodiments, insulationlayer 1278 may include one or more individual sections of insulationlayers wrapped around conductor 1112. Conductor 1112 may be placed inconduit 1176 after insulation layer 1278 has been placed on theconductor. Insulation layer 1278 may electrically insulate conductor1112 from conduit 1176.

[1255] In an embodiment of a conductor-in-conduit heat source, a conduitmay be pressurized with a fluid to inhibit a large pressure differencebetween pressure in the conduit and pressure in the formation. Balancedpressure or a small pressure difference may inhibit deformation of theconduit during use. The fluid may increase conductive heat transfer fromthe conductor to the conduit. The fluid may include, but is not limitedto, a gas such as helium, nitrogen, air, or mixtures thereof. The fluidmay inhibit arcing between the conductor and the conduit. If air and/orair mixtures are used to pressurize the conduit, the air and/or airmixtures may react with materials of the conductor and the conduit toform an oxide layer on a surface of the conductor and/or an oxide layeron an inner surface of the conduit. The oxide layer may inhibit arcing.The oxide layer may make the conductor and/or the conduit more resistantto corrosion.

[1256] Reducing the amount of heat losses to an overburden of aformation may increase an efficiency of a heat source. The efficiency ofthe heat source may be determined by the energy transferred into theformation through the heat source as a fraction of the energy input intothe heat source. In other words, the efficiency of the heat source maybe a function of energy that actually heats a desired portion of theformation divided by the electrical power (or other input power)provided to the heat source. To increase the amount of energy actuallytransferred to the formation, heating losses to the overburden may bereduced. Heating losses in the overburden may be reduced for electricalheat sources by the use of relatively low resistance conductors in theoverburden that couple a power supply to the heat source. Alternatingelectrical current flowing through certain conductors (e.g., carbonsteel conductors) tends to flow along the skin of the conductors. Thisskin depth effect may increase the resistance heating at the outersurface of the conductor (i.e., the current flows through only a smallportion of the available metal) and thus increase heating of theoverburden. Electrically conductive casings, coatings, wiring, and/orcladdings may be used to reduce the electrical resistance of a conductorused in the overburden. Reducing the electrical resistance of theconductor in the overburden may reduce electricity losses to heating theconduit in the overburden portion and thereby increase the availableelectricity for resistive heating in portions of the conductor below theoverburden.

[1257] As shown in FIG. 65, low resistance section 1118 may be coupledto conductor 1112. Low resistance section 1118 may be placed inoverburden 524. Low resistance section 1118 may be, for example, acarbon steel conductor. Carbon steel may be used to provide mechanicalstrength for the heat source in overburden 524. In an embodiment, anelectrically conductive coating may be coated on low resistance section1118 to further reduce an electrical resistance of the low resistanceconductor. In some embodiments, the electrically conductive coating maybe coated on low resistance section 1118 during assembly of the heatsource. In other embodiments, the electrically conductive coating may becoated on low resistance section 1118 after installation of the heatsource in opening 544.

[1258] In some embodiments, the electrically conductive coating may besprayed on low resistance section 1118. For example, the electricallyconductive coating may be a sprayed on thermal plasma coating. Theelectrically conductive coating may include conductive materials suchas, but not limited to, aluminum or copper. The electrically conductivecoating may include other conductive materials that can be thermalplasma sprayed. In certain embodiments, the electrically conductivecoating may be coated on low resistance section 1118 such that theresistance of the low resistance conductor is reduced by a factor ofgreater than about 2. In some embodiments, the resistance is lowered bya factor of greater than about 4 or about 5. The electrically conductivecoating may have a thickness of between 0.1 mm and 0.8 mm. In anembodiment, the electrically conductive coating may have a thickness ofabout 0.25 mm. The electrically conductive coating may be coated on lowresistance conductors used with other types of heat sources such as, forexample, insulated conductor heat sources, elongated member heatsources, etc.

[1259] In another embodiment, a cladding may be coupled to lowresistance section 1118 to reduce the electrical resistance inoverburden 524. FIG. 86 depicts a cross-sectional view of a portion ofcladding section 1256 of conductor-in-conduit heater. Cladding section1256 may be coupled to the outer surface of low resistance section 1118.Cladding sections 1256 may also be coupled to an inner surface ofconduit 1176. In certain embodiments, cladding sections may be coupledto inner surface of low resistance section 1118 and/or outer surface ofconduit 1176. In some embodiments, low resistance section 1118 mayinclude one or more sections of individual low resistance sections 1118coupled together. Conduit 1176 may include one or more sections ofindividual conduits 1176 coupled together.

[1260] Individual cladding sections 1256 may be coupled to eachindividual low resistance section 1118 and/or conduit 1176, as shown inFIG. 86. A gap may remain between each cladding section 1256. The gapmay be at a location of a coupling between low resistance sections 1118and/or conduits 1176. For example, the gap may be at a thread or weldjunction between low resistance sections 1118 and/or conduits 1176. Thegap may be less than about 4 cm in length. In certain embodiments, thegap may be less than about 5 cm in length or less than 6 cm in length.In some embodiments, there may be substantially no gap between claddingsections 1256.

[1261] Cladding section 1256 may be a conduit (or tubing) of relativelyelectrically conductive material. Cladding section 1256 may be a conduitthat tightly fits against a surface of low resistance section 1118and/or conduit 1176. Cladding section 1256 may include non-ferromagneticmetals that have a relatively high electrical conductivity. For example,cladding section 1256 may include copper, aluminum, brass, bronze, orcombinations thereof. Cladding section 1256 may have a thickness betweenabout 0.2 cm and about 1 cm. In some embodiments, low resistance section1118 has an outside diameter of about 2.5 cm and conduit 1176 has aninside diameter of about 7.3 cm. In an embodiment, cladding section 1256coupled to low resistance section 1118 is copper tubing with a thicknessof about 0.32 cm (about ⅛ inch) and an inside diameter of about 2.5 cm.In an embodiment, cladding section 1256 coupled to conduit 1176 iscopper tubing with a thickness of about 0.32 cm (about ⅛ inch) and anoutside diameter of about 7.3 cm. In certain embodiments, claddingsection 1256 has a thickness between about 0.20 cm and about 1.2 cm.

[1262] In certain embodiments, cladding section 1256 is brazed to lowresistance section 1118 and/or conduit 1176. In other embodiments,cladding section 1256 may be welded to low resistance section 1118and/or conduit 1176. In one embodiment, cladding section 1256 isEverdur® (silicon bronze) welded to low resistance section 1118 and/orconduit 1176. Cladding section 1256 may be brazed or welded to lowresistance section 1118 and/or conduit 1176 depending on the types ofmaterials used in the cladding section, the low resistance conductor,and the conduit. For example, cladding section 1256 may include copperthat is Everdur® welded to low resistance section 1118, which includescarbon steel. In some embodiments, cladding section 1256 may bepre-oxidized to inhibit corrosion of the cladding section during use.

[1263] Using cladding section 1256 coupled to low resistance section1118 and/or conduit 1176 may inhibit a significant temperature rise inthe overburden of a formation during use of the heat source (i.e.,reduce heat losses to the overburden). For example, using a coppercladding section of about 0.3 cm thickness may decrease the electricalresistance of a carbon steel low resistance conductor by a factor ofabout 20. The lowered resistance in the overburden section of the heatsource may provide a relatively small temperature increase adjacent tothe wellbore in the overburden of the formation. For example, supplyinga current of about 500 A into an approximately 1.9 cm diameter lowresistance conductor (schedule 40 carbon steel pipe) with a coppercladding of about 0.3 cm thickness produces a maximum temperature ofabout 93° C. at the low resistance conductor. This relatively lowtemperature in the low resistance conductor may transfer relativelylittle heat to the formation. For a fixed voltage at the power source,lowering the resistance of the low resistance conductor may increase thetransfer of power into the heated section of the heat source (e.g.,conductor 1112). For example, a 600 volt power supply may be used tosupply power to a heat source through about a 300 m overburden and intoabout a 260 m heated section. This configuration may supply about 980watts per meter to the heated section. Using a copper cladding sectionof about 0.3 cm thickness with a carbon steel low resistance conductormay increase the transfer of power into the heated section by up toabout 15% compared to using the carbon steel low resistance conductoronly.

[1264] In some embodiments, cladding section 1256 may be coupled toconductor 1112 and/or conduit 1176 by a “tight fit tubing” (TFT) method.TFT is commercially available from vendors such as Kuroki (Japan) orKarasaki Steel (Japan). The TFT method includes cryogenically cooling aninner pipe or conduit, which is a tight fit to an outer pipe. The cooledinner pipe is inserted into the heated outer pipe or conduit. Theassembly is then allowed to return to an ambient temperature. In somecases, the inner pipe can be hydraulically expanded to bond tightly withthe outer pipe.

[1265] Another method for coupling a cladding section to a conductor ora conduit may include an explosive cladding method. In explosivecladding, an inner pipe is slid into an outer pipe. Primer cord or othertype of explosive charge may be set off inside the inner pipe. Theexplosive blast may bond the inner pipe to the outer pipe.

[1266] Electromagnetically formed cladding may also be used for claddingsection 1256. An inner pipe and an outer pipe may be placed in a waterbath. Electrodes attached to the inner pipe and the outer pipe may beused to create a high potential between the inner pipe and the outerpipe. The potential may cause sudden formation of bubbles in the baththat bond the inner pipe to the outer pipe.

[1267] In another embodiment, cladding section 1256 may be arc welded toa conductor or conduit. For example, copper may be arc deposited and/orwelded to a stainless steel pipe or tube.

[1268] In some embodiments, cladding section 1256 may be formed withplasma powder welding (PPW). PPW formed material may be obtained fromDaido Steel Co. (Japan). In PPW, copper powder is heated to form aplasma. The hot plasma may be moved along the length of a tube (e.g., astainless steel tube) to deposit the copper and form the coppercladding.

[1269] Cladding section 1256 may also be formed by billet co-extrusion.A large piece of cladding material may be extruded along a pipe to forma desired length of cladding along the pipe.

[1270] In certain embodiments, forge welding (e.g., shielded active gaswelding) may be used to form cladding section 1256 on a low resistancesection and/or conduit. Forge welding may be used to form a uniform weldthrough the cladding section and the low resistance section or conduit.In some embodiments, forge welding may be used to couple portions of lowresistance sections and/or conduits with cladding sections 1256. FIG. 86depicts an embodiment of portions of low resistance sections 1118,conduits 1176, and cladding sections 1256 aligned for a forge weldingprocess. Portions of low resistance sections 1118 and/or conduits 1176with cladding sections 1256 to be coupled may be held at a certainspacing before welding, as shown in FIG. 86. Spacers and/or roboticcontrol may be used to maintain the certain spacing between the portionsof low resistance sections and/or conduits. The portions of lowresistance sections 1118 and/or conduits 1176 along with claddingsections 1256 may be forge welded. Portions of cladding sections 1256may extend beyond the edges of portions of low resistance sections 1118or conduits 1176 such that cladding sections 1256 are joined together(or touch) before low resistance sections 148 or conduits 1176 arejoined. Touching the cladding sections first may ensure an electricalconnection between each of the joined cladding sections. If the claddingsections are not joined first, the cladding sections may be disconnectedby outward bulging of the low resistance sections or conduits as theyare joined. The portions of low resistance sections 1118, conduits 1176,and/or cladding sections 1256 to be joined may also have taperedprofiles on each end of the portions. The tapered profiles may produce amore cylindrical profile at the weld joint after welding by allowing forthermal expansion of the ends of the welded portions during the weldingprocess.

[1271] Another method is to start with strips of copper and carbon steelthat are bonded together by tack welding or another suitable method. Thecomposite strip is drawn through a shaping unit to form a cylindricallyshaped tube. The cylindrically shaped tube is seam weldedlongitudinally. The resulting tube may be coiled onto a spool.

[1272] Another possible embodiment for reducing the electricalresistance of the conductor in the overburden is to form low resistancesection 1118 from low resistance metals (e.g., metals that are used incladding section 1256). A polymer coating may be placed on some of thesemetals to inhibit corrosion of the metals (e.g., to inhibit corrosion ofcopper or aluminum by hydrogen sulfide).

[1273] In some embodiments, a cladding section may be coupled to aconductor or a conduit within a heated section of a heat source (e.g.,conductor 1112 or conduit 1176 in heated section 1234 as shown in FIG.75). The cladding section may be coupled to a conductor or a conduit ina heated section to reduce the cost of materials within the heatedsection. For example, the conductor and/or the conduit may be made ofcarbon steel while the cladding section is made of stainless steel.Since alternating electrical current flowing through certain conductors(e.g., steel conductors) tends to flow along the skin of the conductors,a majority of the electricity may propagate through the stainless steelcladding section. Heat may be generated by the electrical currentflowing through the stainless steel cladding section, which has a higherelectrical resistance. Carbon steel (which is typically cheaper thanstainless steel) may be used to provide mechanical support for thestainless steel cladding sections.

[1274] Increasing the emissivity of a conductive heat source mayincrease the efficiency with which heat is transferred to a formation.An emissivity of a surface affects the amount of radiative heat emittedfrom the surface and the amount of radiative heat absorbed by thesurface. In general, the higher the emissivity a surface has, thegreater the radiation from the surface or the absorption of heat by thesurface. Thus, increasing the emissivity of a surface increases theefficiency of heat transfer because of the increased radiation of energyfrom the surface into the surroundings. For example, increasing theemissivity of a conductor in a conductor-in-conduit heat source mayincrease the efficiency with which heat is transferred to the conduit,as shown by the following equation: $\begin{matrix}{{{Q\&} = \frac{2\pi \quad r_{1}{\sigma \left( {T_{1}^{4} - T_{2}^{4}} \right)}}{\frac{1}{ɛ_{1}} + {\left( \frac{r_{1}}{r_{2}} \right)\left( {\frac{1}{ɛ_{2}} - 1} \right)}}};} & (41)\end{matrix}$

[1275] where

is the rate of heat transfer between a cylindrical conductor and aconduit, r₁ is the radius of the conductor, r₂ is the radius of theconduit, T₁ is the temperature at the conductor, T₂ is the temperatureat the conduit, σ is the Stefan-Boltzmann constant (5.670×10⁻⁸J·K⁻⁴·m⁻²·s⁻¹), ε₁ is the emissivity of the conductor, and F2 is theemissivity of the conduit. According to EQN. 41, increasing theemissivity of the conductor increases the heat transfer between theconductor and the conduit. Accordingly, for a constant heat transferrate, increasing the emissivity of the conductor decreases thetemperature difference between the conductor and the conduit (i.e.,increases the temperature of the conduit for a given conductortemperature). Increasing the temperature of the conduit increases theamount of heat transfer to the formation.

[1276] In an embodiment, a conductor and/or conduit may be treated toincrease the emissivity of the conductor and/or conduit materials.Treating the conductor and/or conduit may include roughening a surfaceof the conductor or conduit and/or oxidizing the conductor or conduit.In some embodiments, a conductor and/or conduit may be roughened and/oroxidized prior to assembly of a heat source. In some embodiments, aconductor and/or conduit may be roughened and/or oxidized after assemblyand/or installation into a formation (e.g., an oxidizing fluid may beintroduced into an annular space between the conductor and the conduitwhen heating a portion of the formation to pyrolysis temperatures sothat the heat generated in the conductor oxidizes the conductor and theconduit). The treatment method may be used to treat inner surfacesand/or outer surfaces, or portions thereof, of conductors or conduits.In certain embodiments, the outer surface of a conductor and the innersurface of a conduit are treated to increase the emissivities of theconductor and the conduit.

[1277] In an embodiment, surfaces of a conductor, or a portion of thesurface, may be roughened. The roughened surface of the conductor may bethe outer surface of the conductor. The surface of the conductor may beroughened by, but is not limited to being roughened by, sandblasting orbeadblasting the surface, peening the surface, emery grinding thesurface, or using an electrostatic discharge method on the surface. Forexample, the surface of the conductor may be sand blasted with fineparticles to roughen the surface. The conductor may also be treated bypre-oxidizing the surface of the conductor (i.e., heating the conductorto an oxidation temperature before use of the conductor). Pre-oxidizingthe surface of the conductor may include heating the conductor to atemperature between about 850° C. and about 950° C. The conductor may beheated in an oven or furnace. The conductor may be heated in anoxidizing atmosphere (e.g., an oven with a charge of an oxidizing fluidsuch as air). In an embodiment, a 304H stainless steel conductor isheated in a furnace at a temperature of about 870° C. for about 2 hours.If the surface of the 304H stainless steel conductor is roughened priorto heating the conductor in the furnace, the emissivity of the 304Hstainless steel conductor may be increased from about 0.5 to about 0.85.Increasing the emissivity of the conductor may reduce an operatingtemperature of the conductor. Operating the conductor at lowertemperatures may increase an operational lifetime of the conductor. Forexample, operating the conductor at lower temperatures may reduce creepand/or corrosion.

[1278] In some embodiments, applying a coating to a conductor or conduitmay increase the emissivity of a conductor or a conduit and increase theefficiency of heat transfer to the formation. An electrically insulatingand thermally conductive coating may be placed on a conductor and/orconduit. The electrically insulating coating may inhibit arcing betweenthe conductor and the conduit. Arcing between the conductor and theconduit may cause shorting between the conductor and the conduit. Arcingmay also produce hot spots and/or cold spots on either the conductor orthe conduit. In some embodiments, a coating or coatings on portions of aconduit and/or a conductor may increase emissivity, electricallyinsulate, and promote thermal conduction.

[1279] As shown in FIG. 65, conductor 1112 and conduit 1176 may beplaced in opening 544 in hydrocarbon layer 522. In an embodiment, anelectrically insulative, thermally conductive coating is placed onconductor 1112 and conduit 1176 (e.g., on an outside surface of theconductor and an inside surface of the conduit). In some embodiments,the electrically insulative, thermally conductive coating is placed onconductor 1112. In other embodiments, the electrically insulative,thermally conductive coating is placed on conduit 1176. The electricallyinsulative, thermally conductive coating may electrically insulateconductor 1112 from conduit 1176. The electrically insulative, thermallyconductive coating may inhibit arcing between conductor 1112 and conduit1176. In certain embodiments, the electrically insulative, thermallyconductive coating maintains an emissivity of conductor 1112 or conduit1176 (i.e., inhibits the emissivity of the conductor or conduit fromdecreasing). In other embodiments, the electrically insulative,thermally conductive coating increases an emissivity of conductor 1112and/or conduit 1176. The electrically insulative, thermally conductivecoating may include, but is not limited to, oxides of silicon, aluminum,and zirconium, or combinations thereof. For example, silicon oxide maybe used to increase an emissivity of a conductor or conduit whilealuminum oxide may be used to provide better electrical insulation andthermal conductivity. Thus, a combination of silicon oxide and aluminumoxide may be used to increase emissivity while providing improvedelectrical insulation and thermal conductivity. In an embodiment,aluminum oxide is coated on conductor 1112 to electrically insulate theconductor followed by a coating of silicon oxide to increase theemissivity of the conductor.

[1280] In an embodiment, the electrically insulative, thermallyconductive coating is sprayed on conductor 1112 or conduit 1176. Thecoating may be sprayed on during assembly of the conductor-in-conduitheat source. In some embodiments, the coating is sprayed on beforeassembling the conductor-in-conduit heat source. For example, thecoating may be sprayed on conductor 1112 or conduit 1176 by amanufacturer of the conductor or conduit. In certain embodiments, thecoating is sprayed on conductor 1112 or conduit 1176 before theconductor or conduit is coiled onto a spool for installation. In otherembodiments, the coating is sprayed on after installation of theconductor-in-conduit heat source.

[1281] In a heat source embodiment, a perforated conduit may be placedin the opening formed in the hydrocarbon containing formation proximateand external to the conduit of a conductor-in-conduit heater. Theperforated conduit may remove fluids formed in an opening in theformation to reduce pressure adjacent to the heat source. A pressure maybe maintained in the opening such that deformation of the first conduitis inhibited. In some embodiments, the perforated conduit may be used tointroduce a fluid into the formation adjacent to the heat source. Forexample, in some embodiments, hydrogen gas may be injected into theformation adjacent to selected heat sources to increase a partialpressure of hydrogen during in situ conversion.

[1282]FIG. 87 illustrates an embodiment of a conductor-in-conduit heaterthat may heat a hydrocarbon containing formation. Second conductor 1280may be disposed in conduit 1176 in addition to conductor 1112. Secondconductor 1280 may be coupled to conductor 1112 using connector 1282located near a lowermost surface of conduit 1176. Second conductor 1280may be a return path for the electrical current supplied to conductor1112. For example, second conductor 1280 may return electrical currentto wellhead 1162 through low resistance second conductor 1284 inoverburden casing 1120. Second conductor 1280 and conductor 1112 may beformed of elongated conductive material. Second conductor 1280 andconductor 1112 may be a stainless steel rod having a diameter ofapproximately 2.4 cm. Connector 1282 may be flexible. Conduit 1176 maybe electrically isolated from conductor 1112 and second conductor 1280using centralizers 1198. The use of a second conductor may eliminate theneed for a sliding connector. The absence of a sliding connector mayextend the life of the heater. The absence of a sliding connector mayallow for isolation of applied power from hydrocarbon layer 522.

[1283] In a heat source embodiment that utilizes second conductor 1280,conductor 1112 and the second conductor may be coupled by a flexibleconnecting cable. The bottom of the first and second conductor may haveincreased thicknesses to create low resistance sections. The flexibleconnector may be made of stranded copper covered with rubber insulation.

[1284] In a heat source embodiment, a first conductor and a secondconductor may be coupled to a sliding connector within a conduit. Thesliding connector may include insulating material that inhibitselectrical coupling between the conductors and the conduit. The slidingconnector may accommodate thermal expansion and contraction of theconductors and conduit relative to each other. The sliding connector maybe coupled to low resistance sections of the conductors and/or to a lowtemperature portion of the conduit.

[1285] In a heat source embodiment, the conductor may be formed ofsections of various metals that are welded or otherwise joined together.The cross-sectional area of the various metals may be selected to allowthe resulting conductor to be long, to be creep resistant at highoperating temperatures, and/or to dissipate desired amounts of heat perunit length along the entire length of the conductor. For example, afirst section may be made of a creep resistant metal (such as, but notlimited to, Inconel 617 or HR120), and a second section of the conductormay be made of 304 stainless steel. The creep resistant first sectionmay help to support the second section. The cross-sectional area of thefirst section may be larger than the cross-sectional area of the secondsection. The larger cross-sectional area of the first section may allowfor greater strength of the first section. Higher resistivity propertiesof the first section may allow the first section to dissipate the sameamount of heat per unit length as the smaller cross-sectional areasecond section.

[1286] In some embodiments, the cross-sectional area and/or the metalused for a particular conduit section may be chosen so that a particularsection provides greater (or lesser) heat dissipation per unit lengththan an adjacent section. More heat may be provided near an interfacebetween a hydrocarbon layer and a non-hydrocarbon layer (e.g., theoverburden and the hydrocarbon layer and/or an underburden and thehydrocarbon layer) to counteract end effects and allow for more uniformheat dissipation into the hydrocarbon containing formation.

[1287] In a heat source embodiment, a conduit may have a variable wallthickness. Wall thickness may be thickest adjacent to portions of theformation that do not need to be fully heated. Portions of formationthat do not need to be fully heated may include layers of formation thathave low grade, little, or no hydrocarbon material.

[1288] In an embodiment of heat sources placed in a formation, a firstconductor, a second conductor, and a third conductor may be electricallycoupled in a 3-phase Y electrical configuration. Each of the conductorsmay be a part of a conductor-in-conduit heater. The conductor-in-conduitheaters may be located in separate wellbores within the formation. Theouter conduits may be electrically coupled together or conduits may beconnected to ground. The 3-phase Y electrical configuration may providea safer and more efficient method to heat a hydrocarbon containingformation than using a single conductor. The first, second, and thirdconduits may be electrically isolated from the first, second, and thirdconductors. Each conductor-in-conduit heater in a 3-phase Y electricalconfiguration may be dimensioned to generate approximately 650 watts permeter of conductor to approximately 1650 watts per meter of conductor.

[1289] Heat may be generated by the conductor-in-conduit heater withinan open wellbore. Generated heat may radiatively heat a portion of ahydrocarbon containing formation adjacent to the conductor-in-conduitheater. To a lesser extent, gas conduction adjacent to theconductor-in-conduit heater heats the portion of the formation. Using anopen wellbore completion may reduce casing and packing costs associatedwith filling the opening with a material to provide conductive heattransfer between the insulated conductor and the formation. In addition,heat transfer by radiation may be more efficient than heat transfer byconduction in a formation, so the heaters may be operated at lowertemperatures using radiative heat transfer. Operating at a lowertemperature may extend the life of the heat source and/or reduce thecost of material needed to form the heat source.

[1290] The conductor-in-conduit heater may be installed in opening 544.In an embodiment, the conductor-in-conduit heater may be installed intoa well by sections. For example, a first section of theconductor-in-conduit heater may be suspended in a wellbore by a rig. Thesection may be about 12 m in length. A second section (e.g., ofsubstantially similar length) may be coupled to the first section in thewell. The second section may be coupled by welding the second section tothe first section and/or with threads disposed on the first and secondsection. An orbital welder disposed at the wellhead may weld the secondsection to the first section. The first section may be lowered into thewellbore by the rig. This process may be repeated with subsequentsections coupled to previous sections until a heater of desired lengthis placed in the wellbore. In some embodiments, three sections may bewelded together prior to being placed in the wellbore. The welds may beformed and tested before the rig is used to attach the three sections toa string already placed in the ground. The three sections may be liftedby a crane to the rig. Having three sections already welded together mayreduce installation time of the heat source.

[1291] Assembling a heat source at a location proximate a formation(e.g., at the site of a formation) may be more economical than shippinga pre-formed heat source and/or conduits to the hydrocarbon containingformation. For example, assembling the heat source at the site of theformation may reduce costs for transporting assembled heat sources overlong distances. In addition, heat sources may be more easily assembledin varying lengths and/or of varying materials to meet specificformation requirements at the formation site. For example, a portion ofa heat source that is to be heated may be made of a material (e.g., 304stainless steel or other high temperature alloy) while a portion of theheat source in the overburden may be made of carbon steel. Forming theheat source at the site may allow the heat source to be specificallymade for an opening in the formation so that the portion of the heatsource in the overburden is carbon steel and not a more expensive, heatresistant alloy. Heat source lengths may vary due to varying formationlayer depths and formation properties. For example, a formation may havea varying thickness and/or may be located underneath rolling terrain,uneven surfaces, and/or an overburden with a varying thickness. Heatsources of varying length and of varying materials may be assembled onsite in lengths determined by the depth of each opening in theformation.

[1292]FIG. 88 depicts an embodiment for assembling aconductor-in-conduit heat source and installing the heat source in aformation. The conductor-in-conduit heat source may be assembled inassembly facility 1286. In some embodiments, the heat source isassembled from conduits shipped to the formation site. In otherembodiments, heat sources may be made from plate stock that is formedinto conduits at the assembly facility. An advantage of forming aconduit at the assembly facility may be that a surface of plate stockmay be treated with a desired coating (e.g., a coating that allows theemissivity to approach one) or cladding (e.g., copper cladding) beforeforming the conduit so that the treated surface is an inside surface ofthe conduit. In some embodiments, portions of heat sources may be formedfrom plate stock at the assembly facility, while other portions of theheat source may be formed from conduits shipped to the formation site.

[1293] Individual conductor-in-conduit heat source 1288 may includeconductor 1112 and conduit 1176 as shown in FIG. 89. In an embodiment,conductor 1112 and conduit 1176 heat sources may be made of a number ofjoined together sections. In an embodiment, each section is a standard40 ft (12.2 m) section of pipe. Other section lengths may also be formedand/or utilized. In addition, sections of conductor 1112 and/or conduit1176 may be treated in assembly facility 1286 before, during, or afterassembly. The sections may be treated, for example, to increase anemissivity of the sections by roughening and/or oxidation of thesections.

[1294] Each conductor-in-conduit heat source 1288 may be assembled in anassembly facility. Components of conductor-in-conduit heat source 1288may be placed on or within individual conductor-in-conduit heat source1288 in the assembly facility. Components may include, but are notlimited to, one or more centralizers, low resistance sections, slidingconnectors, insulation layers, and coatings, claddings, or couplingmaterials.

[1295] As shown in FIG. 88, each individual conductor-in-conduit heatsource 1288 may be coupled to at least one individualconductor-in-conduit heat source 1288 at coupling station 1290 to formconductor-in-conduit heat source of a desired length. The desired lengthmay be, for example, a length of a conductor-in-conduit heat sourcespecified for a selected opening in a formation. In certain embodiments,coupling individual conductor-in-conduit heat source 1288 to at leastone additional individual conductor-in-conduit heat source 1288 includeswelding the individual conductor-in-conduit heat source to at least oneadditional individual conductor-in-conduit heat source. In oneembodiment, welding each individual conductor-in-conduit heat source1288 to an additional individual conductor-in-conduit heat source isaccomplished by forge welding two adjacent sections together.

[1296] In some embodiments, sections of welded togetherconductor-in-conduit heat source of a desired length are placed on abench, holding tray or in an opening in the ground until the entirelength of the heat source is completed. Weld integrity may be tested aseach weld is formed. Weld integrity may be tested by a non-destructivetesting method such as x-ray testing, acoustic testing, and/orelectromagnetic testing. Weld integrity may be tested at a testingstation 1292. After an entire length of conductor-in-conduit heat sourceof the desired length is completed, the conductor-in-conduit heat sourceof the desired length may be coiled onto spool 1294 in a direction ofarrow 1296. Coiling conductor-in-conduit heat source 1288 of the desiredlength may make the heat source easier to transport to an opening in aformation. For example, conductor-in-conduit heat source 1288 of thedesired length may be more easily transported by truck or train to anopening in the formation.

[1297] In some embodiments, a set length of welded togetherconductor-in-conduit may be coiled onto spool 1294 while other sectionsare being formed at coupling station 1290. In some embodiments, theassembly facility may be a mobile facility (e.g., placed on one or moretrain cars or semi-trailers) that can be moved to an opening in aformation. After forming a welded together length ofconductor-in-conduit with components (e.g., centralizers, coatings,claddings, sliding connectors), the conductor-in-conduit length may belowered into the opening in the formation.

[1298] In certain embodiments, conductor-in-conduit heat source 1288 ofa desired length may be tested at testing station 1292 before coilingthe heat source. Testing station 1292 may be used to test a completedconductor-in-conduit heat source or sections of the conductor-in-conduitheat source. Testing station 1292 may be used to test selectedproperties of conductor-in-conduit heat source. For example, testingstation 1292 may be used to test properties such as, but not limited to,electrical conductivity, weld integrity, thermal conductivity,emissivity, and mechanical strength. In one embodiment, testing station1292 is used to test weld integrity with an Electro-Magnetic AcousticTransmission (EMAT) weld inspection technique.

[1299] Conductor-in-conduit heat source 1288 may be coiled onto spool1294 for transporting from assembly facility 1286 to an opening in aformation and installation into the opening. In an embodiment, assemblyfacility 1286 is located at a site of the formation. For example,assembly facility 1286 may be part of a treatment facility used to treatfluids from the formation or located proximate to the formation (e.g.,less than about 10 km from the formation or, in some embodiments, lessthan about 20 km or less than about 30 km). Other types of heat sources(e.g., insulated conductor heat sources, natural distributed combustorheat sources, etc.) may also be assembled in assembly facility 1286.These other heat sources may also be spooled onto spool 1294,transported to an opening in a formation, and installed into theopening. In some embodiments, spool 1294 may be included as a portion ofa coiled tubing rig (e.g., for an insulated conductor heat source or aconductor-in-conduit heat source).

[1300] Transportation of conductor-in-conduit heat source 1288 to anopening in a formation is represented by arrow 1298 in FIG. 88.Transporting conductor-in-conduit heat source 1288 may includetransporting the heat source on a bed, trailer, a cart of a truck ortrain, or a coiled tubing unit. In some embodiments, more than one heatsource may be placed on the bed. Each heat source may be installed in aseparate opening in the formation. In one embodiment, a train system(e.g., rail system) may be set up to transport heat sources fromassembly facility 1286 to each of the openings in the formation. In someinstances, a lift and move track system may be used in which traintracks are lifted and moved to another location after use in onelocation.

[1301] After spool 1294 with conductor-in-conduit heat source 1288 hasbeen transported to opening 544, the heat source may be uncoiled andinstalled into the opening in a direction of arrow 1300.Conductor-in-conduit heat source 1288 may be uncoiled from spool 1294while the spool remains on the bed of a truck or train. In someembodiments, more than one conductor-in-conduit heat source 1288 may beinstalled at one time. In one embodiment, more than one heat source maybe installed into one opening 544. Spool 1294 may be re-used foradditional heat sources after installation of conductor-in-conduit heatsource 1288. In some embodiments, spool 1294 may be used to removeconductor-in-conduit heat source 1288 from the opening.Conductor-in-conduit heat source 1288 of desired length may be re-coiledonto spool 1294 as the heat source is removed from opening 544.Subsequently, conductor-in-conduit heat source 1288 may be re-installedfrom spool 1294 into opening 544 or transported to an alternate openingin the formation and installed in the alternate opening.

[1302] In certain embodiments, conductor-in-conduit heat source 1288, orany heat source (e.g., an insulated conductor heat source or naturaldistributed combustor), may be installed such that the heat source isremovable from opening 544. The heat source may be removable so that theheat source can be repaired or replaced if the heat source fails orbreaks. In other instances, the heat source may be removed from theopening and transported and redeployed in another opening in theformation (or in a different formation) at a later time. In otherinstances, the heat source may be removed and replaced with a lower costheater at later times of heating a formation. Being able to remove,replace, and/or redeploy a heat source may be economically favorable forreducing equipment and/or operating costs. In addition, being able toremove and replace an ineffective heater may eliminate the need to formwellbores in close proximity to existing wellbores that have failedheaters in a heated or heating formation.

[1303] In some embodiments, a conduit of a desired length may be placedinto opening 544 before a conductor of the desired length. The conductorand the conduit of the desired length may be assembled in assemblyfacility 1286. The conduit of the desired length may be installed intoopening 544. After installation of the conduit of the desired length,the conductor of the desired length may be installed into opening 544.In an embodiment, the conduit and the conductor of the desired lengthare coiled onto a spool in assembly facility 1286 and uncoiled from thespool for installation into opening 544. Components (e.g., centralizers1198, sliding connectors 1202, etc.) may be placed on the conductor orconduit as the conductor is installed into the conduit and opening 544.

[1304] In certain embodiments, centralizer 1198 may include at least twoportions coupled together to form the centralizer (e.g., “clam shell”centralizers). In one embodiment, the portions are placed on a conductorand coupled together as the conductor is installed into a conduit oropening. The portions may be coupled with fastening devices such as, butnot limited to, clamps, bolts, screws, snap-locks, and/or adhesive. Theportions may be shaped such that a first portion fits into a secondportion. For example, an end of the first portion may have a slightlysmaller width than an end of the second portion so that the ends overlapwhen the two portions are coupled.

[1305] In some embodiments, low resistance section 1118 is coupled toconductor-in-conduit heat source 1288 in assembly facility 1286. Inother embodiments, low resistance section 1118 is coupled toconductor-in-conduit heat source 1288 after the heat source is installedinto opening 544. Low resistance section 1118 of a desired length may beassembled in assembly facility 1286. An assembled low resistanceconductor may be coiled onto a spool. The assembled low resistanceconductor may be uncoiled from the spool and coupled toconductor-in-conduit heat source 1288 after the heat source is installedin opening 544. In another embodiment, low resistance section 1118 isassembled as the low resistance conductor is coupled toconductor-in-conduit heat source 1288 and installed into opening 544.Conductor-in-conduit heat source 1288 may be coupled to a support afterinstallation so that low resistance section 1118 is coupled to theinstalled heat source.

[1306] Assembling a desired length of a low resistance conductor mayinclude coupling individual low resistance conductors together. Theindividual low resistance conductors may be plate stock conductorsobtained from a manufacturer. The individual low resistance conductorsmay be coupled to an electrically conductive material to lower theelectrical resistance of the low resistance conductor. The electricallyconductive material may be coupled to the individual low resistanceconductor before assembly of the desired length of low resistanceconductor. In one embodiment, the individual low resistance conductorsmay have threaded ends that are coupled together. In another embodiment,the individual low resistance conductors may have ends that are weldedtogether. Ends of the individual low resistance conductors may be shapedsuch that an end of a first individual low resistance conductor fitsinto an end of a second individual low resistance conductor. Forexample, an end of a first individual low resistance conductor may be afemale-shaped end while an end of a second individual low resistanceconductor is a male-shaped end.

[1307] In another embodiment, a conductor-in-conduit heat source of adesired length may be assembled at a wellbore (or opening) in aformation and installed into the wellbore as the conductor-in-conduitheat source is assembled. Individual conductors may be coupled to form afirst section of a conductor of desired length. Similarly, conduits maybe coupled to form a first section of a conduit of desired length. Thefirst formed sections of the conductor and the conduit may be installedinto the wellbore. The first formed sections of the conductor and theconduit may be electrically coupled at a first end that is installedinto the wellbore. The first sections of the conductor and conduit may,in some embodiments, be coupled substantially simultaneously. Additionalsections of the conductor and/or conduit may be formed during or afterinstallation of the first formed sections. The additional sections ofthe conductor and/or conduit may be coupled to the first formed sectionsof the conductor and/or conduit and installed into the wellbore.Centralizers and/or other components may be coupled to sections of theconductor and/or conduit and installed with the conductor and theconduit into the wellbore.

[1308] A method for coupling conductors or conduits may include a forgewelding method (e.g., shielded active gas (SAG) welding). In anembodiment, forge welding includes arranging ends of the conductorsand/or conduits that are to be interconnected at a selected distance.Seals may be formed against walls of the conduit and/or conductor todefine a chamber. A flushing, reducing fluid may be introduced into thechamber. Each end within the chamber may be heated and moved towardsanother end until the heated ends contact each other. Contacting theheated ends may form a forge weld between the heated ends. The flushing,reducing fluid mixture may include less than 25% by volume of a reducingagent and more than 75% by volume of a substantially inert gas. Theflushing, reducing fluid may inhibit oxidation reactions that canadversely affect weld integrity.

[1309] A flushing fluid mixture with less than 25% by volume of areducing fluid (e.g., hydrogen and/or carbon monoxide) and more than 75%by volume of a substantially inert gas (e.g., nitrogen, argon, and/orcarbon dioxide) may be non-explosive when the flushing fluid mixturecomes into contact with air at elevated temperatures needed to form theforge weld. In some embodiments, the reducing agent may be or includeborax powder and/or beryllium or alkaline hydrites. The flushing fluidmixture may contain a sufficient amount of a reducing gas to flush offoxidized skin from the hot ends that are to be interconnected. In someembodiments, the non-explosive flushing fluid mixture includes between2% by volume and 10% by volume of the reducing fluid and between 90% byvolume and 98% by volume of the substantially inert gas. In certainembodiments, the mixture includes about 5% by volume of the reducingfluid and about 95% by volume of the substantially inert gas. In oneembodiment, a non-explosive flushing fluid mixture includes about 95% byvolume of nitrogen and about 5% by volume of hydrogen. The non-explosiveflushing fluid mixture may also include less than 100 ppm H₂O and/or O₂or, in some cases, less than 15 ppm H₂O and/or O₂.

[1310] A substantially inert gas used during a forge welding procedureis a gas that does not significantly react with the metals to be forgewelded at the pressures and temperatures used during forge welding.Substantially inert gas may be, but is not limited to, noble gases(e.g., helium and argon), nitrogen, or combinations thereof.

[1311] A non-explosive flushing fluid mixture may be formed in-situwithin the chamber. A coating on the conduits and/or conductors may bepresent and/or a solid may be placed in the chamber. When the conduitsand/or conductors are heated, the coating and/or solid may react orphysically transform to the flushing fluid mixture.

[1312] In an embodiment, ends of conductors or conduits are heated bymeans of high frequency electrical heating. The ends may be maintainedat a predetermined spacing of between 1 mm and 4 mm from each other by agripping assembly while being heated. Electrical contacts may be pressedat circumferentially spaced intervals against the wall of each conduitand/or conductor adjacent to the end such that the electrical contactstransmit a high frequency electrical current in a substantiallycircumferential direction in the segment between the electricalcontacts.

[1313] To equalize the level of heating in a circumferential direction,each end may be heated by at least two pairs of electrodes. Theelectrodes of each pair may be pressed at substantially diametricallyopposite positions against walls of the conduits and/or conductors. Thedifferent pairs of electrodes at each end may be activated in analternating manner.

[1314] In one embodiment, two pairs of diametrically opposite electrodesare pressed at angular intervals of substantially 90° against walls ofthe conductors and conduits. In another embodiment, three pairs ofdiametrically opposite electrodes are pressed at angular intervals ofsubstantially 60° against the walls of the conductors and conduits. Inother embodiments, four, five, six or more pairs of diametricallyopposite electrodes may be used and activated in an alternating mannerto equalize the level of heating of the ends in the circumferentialdirection.

[1315] The use of two or more pairs of electrodes may reduce unequalheating of the pipe ends because of over heating of the walls in thedirect vicinity of the electrode. In addition, using two or more pairsof electrodes may reduce heating of the pipe wall halfway between theelectrodes.

[1316] In another embodiment, the ends may be heated by a directresistance heating method. The direct resistance heating method mayinclude transmitting a large current in an axial direction across theconduits and/or conductors while the conduits and/or conductors arepressed together. In another embodiment, the ends may be heated byinduction heating. Induction heating may include using external and/orinternal heating coils to create an electromagnetic field that induceselectrical currents in the conduits and/or conductors. The electricalcurrents may resistively heat the conduits.

[1317] The heating assembly may be used to give the forge welded ends apost weld heat treatment. The post weld heat treatment may includeproviding at least some heating to the ends such that the ends arecooled down at a predetermined temperature decrease rate (i.e., cooldown rate). In some embodiments, the assembly may be equipped with waterand/or forced air injectors to increase and/or control the cool downrate of the forge welded ends.

[1318] In certain embodiments, the quality of the forge weld formedbetween the interconnected conduits and/or conductors is inspected bymeans of an Electro-Magnetic Acoustic Transmission weld inspectiontechnique (EMAT). EMAT may include placing at least one electromagneticcoil adjacent to both sides of the forge welded joint. The coil may beheld at a predetermined distance from the conduits and/or conductorsduring the inspection process. The absence of physical contact betweenthe wall of the hot conduits and/or conductors and the coils of the EMATinspection tool may enable weld inspection immediately after the forgeweld joint has been made.

[1319]FIG. 90 shows an end of tubular 1302 around which two pairs ofdiametrically opposite electrodes 1304, 1306 and 1308, 1310 arearranged. Tubular 1302 may be a conduit or conductor. Tubular 1302 maybe made of electrically conductive material (e.g., stainless steel). Thefirst pair of electrodes 1304, 1306 may be pressed against the outersurface of tubular 1302 and transmit high frequency current 1312 throughthe wall of the tubular as illustrated by arrows 1314. An assembly offerrite bars 1316 may serve to enhance the current density in theimmediate vicinity of the ends of the tubular 1302 and of the adjacenttubular to which tubular 1302 is to be welded.

[1320]FIG. 91 depicts an embodiment with ends 1318A, 1318B of twoadjacent tubulars 1302A and 1302B. Tubulars 1302A, 1302B may be heatedby two sets of diametrically opposite electrodes 1304A, 1306A, 1308A,1310A and 1304B, 1306B, 1308B and 1310B, respectively. Tubular ends1318A, 1318B may be located at a few millimeters distant from each otherduring a heating phase. The larger spacing of current density shown bydotted lines 1314 midway between electrodes 1304A, 1306A illustratesthat the current density midway between these electrodes may be lowerthan the current density adjacent to each of the electrodes. The lowercurrent density midway between the electrodes may create a variation inthe heating rate of the tubular ends 1318A, 1318B. To reduce a possibleirregular heating rate, electrodes 1304A, 1306A and 1304B, 1306B may beregularly lifted from the outer surface of tubulars 1302A, 1302B whilethe other electrodes 1308A, 1308B and 1310A, 1310B are pressed againstthe outer surface of tubulars 1302A, 1302B and activated to transmit ahigh frequency current through the ends of the tubulars. By sequentiallyactivating the two sets of diametrically opposite electrodes at eachtubular end, irregular heating of the tubular ends may be inhibited(i.e., heating of the tubular ends may be more uniform).

[1321] All electrodes 1304A-1310A and 1304B-1304B shown in FIG. 91 maybe pressed simultaneously against tubular ends 1318A, 1318B ifalternating current supplied to the electrodes is controlled such thatduring a first part of a current cycle the diametrically oppositeelectrode pairs 1304B, 1306B and 1308A, 1310A transmit a positiveelectrical current as indicated by the “+” sign in FIG. 91, whereaselectrodes 1304A, 1306A, and 1308B, 1310B transmit a negative electricalcurrent as indicated by the “−” sign. During a second part of thealternating current cycle, electrodes 1304B, 1306B, and 1308A, 1310Atransmit a negative electrical current, whereas electrodes 1304A, 1306A,and 1308B, 1310B transmit a positive current into tubulars 1302A, 1302B.Controlling the alternating current in this manner may heat tubular ends1318A, 1318B in a substantially uniform manner.

[1322] The temperature of heated tubular ends 1318A, 1318B may bemonitored by an infrared temperature sensor. When the monitoredtemperature has reached a temperature sufficient to make a forge weld,tubular ends 1318A, 1318B may be pressed onto each other such that aforge weld is made. Tubular ends 1318A, 1318B may be profiled and have asmaller wall thickness than other parts of tubulars 1302A, 1302B tocompensate for the deformation of the tubular ends when the ends areabutted. Profiling the tubular ends may allow tubulars 1302A, 1302B tohave a substantially uniform wall thickness at forge welded ends.

[1323] During the heating phase and while the ends of tubulars 1302A,1302B are moved towards each other, the tubular ends may be encased,both internally and externally, in a chamber 1320. Chamber 1320 may befilled with a non-explosive flushing fluid mixture. The non-explosiveflushing fluid mixture may include more than 75% by volume of nitrogenand less than 25% by volume of hydrogen. In one embodiment, thenon-explosive flushing fluid mixture for interconnecting steel tubulars1302A, 1302B includes about 5% by volume of hydrogen and about 95% byvolume of nitrogen. The flushing fluid pressure in a part of chamber1320 outside the tubulars 1302A, 1302B may be higher than the flushingfluid pressure in a part of the chamber 1320 within the interior of thetubulars such that throughout the heating process the flushing fluidflows along the ends of the tubulars as illustrated by arrows 1322 untilthe ends of the tubulars are forged together. In some embodiments,flushing fluid may flow through the chamber.

[1324] Hydrogen in the flushing fluid may react with oxidized metal onthe ends 1318A, 1318B of the tubulars 1302A, 1302B so that formation ofan oxidized skin is inhibited. Inhibition of an oxidized skin may allowformation of a forge weld with minimal amounts of corroded metalinclusions.

[1325] Laboratory experiments revealed that a good metallurgical bondbetween stainless steel tubulars may be obtained by forge welding with aflushing fluid containing about 5% by volume of hydrogen and about 95%by volume of nitrogen. Experiments also show that such a flushing fluidmixture may be non-explosive during and after forge welding. Two forgewelded stainless steel tubulars failed at a location away from the forgeweld when the tubulars were subjected to testing.

[1326] In an embodiment, the tubular ends are clamped throughout theforge welding process to a gripping assembly. Clamping the tubular endsmay maintain the tubular ends at a predetermined spacing of between 1 mmand 4 mm from each other during the heating phase. The gripping assemblymay include a mechanical stop that interrupts axial movement of theheated tubular ends during the forge welding process after the heatedtubular ends have moved a predetermined distance towards each other. Theheated tubular ends may be pressed into each other such that a highquality forge weld is created without significant deformation of theheated ends.

[1327] In certain embodiments, electrodes 1304A-1310A and 1304B-1310Bmay also be activated to give the forged tubular ends a post weld heattreatment. High frequency current 1312 supplied to the electrodes duringthe post weld heat treatment may be lower than during the heat up phasebefore the forge welding operation. High frequency current 1312 suppliedduring the post weld heat treatment may be controlled in conjunctionwith temperature measured by an infrared temperature sensor(s) such thatthe temperature of the forge welded tubular ends is decreased inaccordance with a predetermined temperature decrease or cooling cycle.

[1328] The quality of the forge weld may be inspected by a hybridelectromagnetic acoustic transmission technique which is known as EMAT.EMAT is described in U.S. Pat. Nos. 5,652,389 to Schaps et al.,5,760,307 to Latimer et al., 5,777,229 to Geier et al., and 6,155,117 toStevens et al., each of which is incorporated by reference as if fullyset forth herein. The EMAT technique makes use of an induction coilplaced at one side of the welded joint. The induction coil may inducemagnetic fields that generate electromagnetic forces in the surface ofthe welded joint. These forces may produce a mechanical disturbance bycoupling to the atomic lattice through a scattering process. Inelectromagnetic acoustic generation, the conversion may take placewithin a skin depth of material (i.e., the metal surface acts as atransducer). The reception may take place in a reciprocal way in areceiving coil. When the elastic wave strikes the surface of theconductor in the presence of a magnetic field, induced currents may begenerated in the receiving coil, similar to the operation of an electricgenerator. An advantage of the EMAT weld inspection technology is thatthe inductive transmission and receiving coils do not have to contactthe welded tubular. Thus, the inspection may be done soon after theforge weld is made (e.g., when the forge welded tubulars are still toohot to allow physical contact with an inspection probe).

[1329] Using the SAG method to weld tubular ends of heat sources mayinhibit changes in the metallurgy of the tubular materials. For example,the elemental composition of the weld joint may be substantially similarto the elemental composition of the tubulars. Inhibiting changes inmetallurgy may reduce the need for heat-treatment of the tubulars beforeuse of the tubulars. The SAG method also appears not to change the grainstructure of the near-weld section of the tubulars. Maintaining thegrain structure of the tubulars may inhibit corrosion and/or creep inthe tubulars during use.

[1330]FIG. 92 illustrates an end view of an embodiment of aconductor-in-conduit heat source heated by diametrically oppositeelectrodes. Conductor 1112 may be placed within conduit 1176. Conductor1112 may be heated by two sets of diametrically opposite electrodes1304, 1306, 1308, 1310. Conduit 1176 may be heated by two sets ofdiametrically opposite electrodes 1324, 1326, 1328, 1330. Conductor 1112and conduits 1176 may be heated and forge welded together as describedin the embodiments of FIGS. 90-91. In some embodiments, two ends ofconductors 1112 are forged welded together and then two ends of conduits1176 are forged together in a second procedure.

[1331]FIG. 93 illustrates a cross-sectional representation of anembodiment of two sections of a conductor-in-conduit heat source beforebeing forge welded. During heating of conductors 1112, 1112A andconduits 1176, 1176A and while the ends of the conductors and theconduits are moved towards each other, ends of the conductors andconduits may be encased in a chamber 1320. Chamber 1320 may be filledwith the non-explosive flushing fluid mixture. Plugs 1332, 1332A may beplaced in the annular space between conductors 1112, 1112A and conduits1176, 1176A. In an embodiment, the plugs may be inflated to seal theannular space. Plugs 1332, 1332A may inhibit the flow of the flushingfluid mixture through the annular space between conductors 1112, 1112Aand conduits 1176, 1176A. The flushing fluid pressure in a part ofchamber 1320 outside the conduits 1176, 1176A may be higher than theflushing fluid pressure inside the conduits and outside conductors 1112,1112A. Similarly, the flushing fluid pressure outside conductors 1112,1112A may be higher than the flushing fluid pressure inside theconductors. Due to the pressure differentials throughout the heatingprocess, the flushing fluid tends to flow along the ends of the tubularsas illustrated by arrows 1334 until the ends of the conductors andconduits are forged together.

[1332]FIG. 94 depicts an embodiment of three horizontal heat sourcesplaced in a formation. Wellbore 1336 may be formed through overburden524 and into hydrocarbon layer 522. Wellbore 1336 may be formed by anystandard drilling method. In certain embodiments, wellbore 1336 isformed substantially horizontally in hydrocarbon layer 522. In someembodiments, wellbore 1336 may be formed at other angles withinhydrocarbon layer 522.

[1333] One or more conduits 1338 may be placed within wellbore 1336. Aportion of wellbore 1336 and/or second wellbores may include casings.Conduit 1338 may have a smaller diameter than wellbore 1336. In anembodiment, wellbore 1336 has a diameter of about 30.5 cm and conduit1338 has a diameter of about 14 cm. In an embodiment, an inside diameterof a casing in conduit 1338 may be about 12 cm. Conduits 1338 may haveextended sections 1340 that extend beyond the end of wellbore 1336 inhydrocarbon layer 522. Extended sections 1340 may be formed inhydrocarbon layer 522 by drilling or other wellbore forming methods. Inan embodiment, extended sections 1340 extend substantially horizontallyinto hydrocarbon layer 522. In certain embodiments, extended sections1340 may somewhat diverge as represented in FIG. 94.

[1334] Perforated casings 1254 may be placed in extended sections 1340of conduits 1338. Perforated casings 1254 may provide support for theextended sections so that collapse of wellbores is inhibited duringheating of the formation. Perforated casings 1254 may be steel (e.g.,carbon steel or stainless steel). Perforated casings 1254 may beperforated liners that expand within the wellbores (expandabletubulars). Expandable tubulars are described in U.S. Pat. Nos. 5,366,012to Lohbeck, and 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein. In anembodiment, perforated casings 1254 are formed by inserting a perforatedcasing into each of extended sections 1340 and expanding the perforatedcasing within each extended section. The perforated casing may beexpanded by pulling an expander tool shaped to push the perforatedcasing towards the wall of the wellbore (e.g., a pig) along the lengthof each extended section 1340. The expander tool may push eachperforated casing beyond the yield point of the perforated casing.

[1335] After installation of perforated casings 1254, heat sources 508may be installed into extended sections 1340. Heat sources 508 may beused to provide heat to hydrocarbon layer 522 along the length ofextended sections 1340. Heat sources 508 may include heat sources suchas conductor-in-conduit heaters, insulated conductor heaters, etc. Insome embodiments, heat sources 508 have a diameter of about 7.3 cm.Perforated casings 1254 may allow for production of formation fluid fromthe heat source wellbores. Installation of heat sources 508 inperforated casings 1254 may also allow the heat sources to be removed ata later time. Heat sources 508 may, for example, be removed for repair,replacement, and/or used in another portion of a formation.

[1336] In an embodiment, an elongated member may be disposed within anopening (e.g., an open wellbore) in a hydrocarbon containing formation.The opening may be an uncased opening in the hydrocarbon containingformation. The elongated member may be a length (e.g., a strip) of metalor any other elongated piece of metal (e.g., a rod). The elongatedmember may include stainless steel. The elongated member may be made ofa material able to withstand corrosion at high temperatures within theopening.

[1337] An elongated member may be a bare metal heater. “Bare metal”refers to a metal that does not include a layer of electricalinsulation, such as mineral insulation, that is designed to provideelectrical insulation for the metal throughout an operating temperaturerange of the elongated member. Bare metal may encompass a metal thatincludes a corrosion inhibiter such as a naturally occurring oxidationlayer, an applied oxidation layer, and/or a film. Bare metal includesmetal with polymeric or other types of electrical insulation that cannotretain electrical insulating properties at typical operating temperatureof the elongated member. Such material may be placed on the metal andmay be thermally degraded during use of the heater.

[1338] An elongated member may have a length of about 650 m. Longerlengths may be achieved using sections of high strength alloys, but suchelongated members may be expensive. In some embodiments, an elongatedmember may be supported by a plate in a wellhead. The elongated membermay include sections of different conductive materials that are weldedtogether end-to-end. A large amount of electrically conductive weldmaterial may be used to couple the separate sections together toincrease strength of the resulting member and to provide a path forelectricity to flow that will not result in arcing and/or corrosion atthe welded connections. In some embodiments, different sections may beforge welded together. The different conductive materials may includealloys with a high creep resistance. The sections of differentconductive materials may have varying diameters to ensure uniformheating along the elongated member. A first metal that has a highercreep resistance than a second metal typically has a higher resistivitythan the second metal. The difference in resistivities may allow asection of larger cross-sectional area, more creep resistant first metalto dissipate the same amount of heat as a section of smallercross-sectional area second metal. The cross-sectional areas of the twodifferent metals may be tailored to result in substantially the sameamount of heat dissipation in two welded together sections of themetals. The conductive materials may include, but are not limited to,617 Inconel, HR-120, 316 stainless steel, and 304 stainless steel. Forexample, an elongated member may have a 60 meter section of 617 Inconel,60 meter section of HR-120, and 150 meter section of 304 stainlesssteel. In addition, the elongated member may have a low resistancesection that may run from the wellhead through the overburden. This lowresistance section may decrease the heating within the formation fromthe wellhead through the overburden. The low resistance section may bethe result of, for example, choosing a electrically conductive materialand/or increasing the cross-sectional area available for electricalconduction.

[1339] In a heat source embodiment, a support member may extend throughthe overburden, and the bare metal elongated member or members may becoupled to the support member. A plate, a centralizer, or other type ofsupport member may be located near an interface between the overburdenand the hydrocarbon layer. A low resistivity cable, such as a strandedcopper cable, may extend along the support member and may be coupled tothe elongated member or members. The low resistivity cable may becoupled to a power source that supplies electricity to the elongatedmember or members.

[1340]FIG. 95 illustrates an embodiment of a plurality of elongatedmembers that may heat a hydrocarbon containing formation. Two or more(e.g., four) elongated members 1342 may be supported by support member1344. Elongated members 1342 may be coupled to support member 1344.using insulated centralizers 1346. Support member 1344 may be a tube orconduit. Support member 1344 may also be a perforated tube. Supportmember 1344 may provide a flow of an oxidizing fluid into opening 544.Support member 1344 may have a diameter between about 1.2 cm and about 4cm and, in some embodiments, about 2.5 cm. Support member 1344,elongated members 1342, and insulated centralizers 1346 may be disposedin opening 544 in hydrocarbon layer 522. Insulated centralizers 1346 maymaintain a location of elongated members 1342 on support member 1344such that lateral movement of elongated members 1342 is inhibited attemperatures high enough to deform support member 1344 or elongatedmembers 1342. Elongated members 1342, in some embodiments, may be metalstrips of about 2.5 cm wide and about 0.3 cm thick stainless steel.Elongated members 1342, however, may also include a pipe or a rod formedof a conductive material. Electrical current may be applied to elongatedmembers 1342 such that elongated members 1342 may generate heat due toelectrical resistance.

[1341] Elongated members 1342 may generate heat of approximately 650watts per meter of elongated members 1342 to approximately 1650 wattsper meter of elongated members 1342. Elongated members 1342 may be attemperatures of approximately 480° C. to approximately 815° C.Substantially uniform heating of a hydrocarbon containing formation maybe provided along a length of elongated members 1342 or greater thanabout 305 m or, maybe even greater than about 610 m.

[1342] Elongated members 1342 may be electrically coupled in series.Electrical current may be supplied to elongated members 1342 usinglead-in conductor 1146. Lead-in conductor 1146 may be coupled towellhead 1162. Electrical current may be returned to wellhead 1162 usinglead-out conductor 1348 coupled to elongated members 1342. Lead-inconductor 1146 and lead-out conductor 1348 may be coupled to wellhead1162 at surface 542 through a sealing flange located between wellhead1162 and overburden 524. The sealing flange may inhibit fluid fromescaping from opening 544 to surface 542 and/or atmosphere. Lead-inconductor 1146 and lead-out conductor 1348 may be coupled to elongatedmembers using a cold pin transition conductor. The cold pin transitionconductor may include an insulated conductor of low resistance. Littleor no heat may be generated in the cold pin transition conductor. Thecold pin transition conductor may be coupled to lead-in conductor 1146,lead-out conductor 1348, and/or elongated members 1342 by splices,mechanical connections and/or welds. The cold pin transition conductormay provide a temperature transition between lead-in conductor 1146,lead-out conductor 1348, and/or elongated members 1342. Lead-inconductor 1146 and lead-out conductor 1348 may be made of low resistanceconductors so that substantially no heat is generated from electricalcurrent passing through lead-in conductor 1146 and lead-out conductor1348.

[1343] Weld beads may be placed beneath centralizers 1346 on supportmember 1344 to fix the position of the centralizers. Weld beads may beplaced on elongated members 1342 above the uppermost centralizer to fixthe position of the elongated members relative to the support member(other types of connecting mechanisms may also be used). When heated,the elongated member may thermally expand downwards. The elongatedmember may be formed of different metals at different locations along alength of the elongated member to allow relatively long lengths to beformed. For example, a “U” shaped elongated member may include a firstlength formed of 310 stainless steel, a second length formed of 304stainless steel welded to the first length, and a third length formed of310 stainless steel welded to the second length. 310 stainless steel ismore resistive than 304 stainless steel and may dissipate approximately25% more energy per unit length than 304 stainless steel of the samedimensions. 310 stainless steel may be more creep resistant than 304stainless steel. The first length and the third length may be formedwith cross-sectional areas that allow the first length and third lengthsto dissipate as much heat as a smaller cross-sectional area of 304stainless steel. The first and third lengths may be positioned close towellhead 1162. The use of different types of metal may allow theformation of long elongated members. The different metals may be, butare not limited to, 617 Inconel, HR120, 316 stainless steel, 310stainless steel, and 304 stainless steel.

[1344] Packing material 1100 may be placed between overburden casing1120 and opening 544. Packing material 1100 may inhibit fluid flowingfrom opening 544 to surface 542 and to inhibit corresponding heat lossestowards the surface. In some embodiments, overburden casing 1120 may beplaced in reinforcing material 1122 in overburden 524. In otherembodiments, overburden casing may not be cemented to the formation.Surface conductor 1174 may be disposed in reinforcing material 1122.Support member 1344 may be coupled to wellhead 1162 at surface 542.Centralizer 1198 may maintain a location of support member 1344 withinoverburden casing 1120. Electrical current may be supplied to elongatedmembers 1342 to generate heat. Heat generated from elongated members1342 may radiate within opening 544 to heat at least a portion ofhydrocarbon layer 522.

[1345] The oxidizing fluid may be provided along a length of theelongated members 1342 from oxidizing fluid source 1094. The oxidizingfluid may inhibit carbon deposition on or proximate the elongatedmembers. For example, the oxidizing fluid may react with hydrocarbons toform carbon dioxide. The carbon dioxide may be removed from the opening.Openings 1350 in support member 1344 may provide a flow of the oxidizingfluid along the length of elongated members 1342. Openings 1350 may becritical flow orifices. In some embodiments, a conduit may be disposedproximate elongated members 1342 to control the pressure in theformation and/or to introduce an oxidizing fluid into opening 544.Without a flow of oxidizing fluid, carbon deposition may occur on orproximate elongated members 1342 or on insulated centralizers 1346.Carbon deposition may cause shorting between elongated members 1342 andinsulated centralizers 1346. or hot spots along elongated members 1342.The oxidizing fluid may be used to react with the carbon in theformation. The heat generated by reaction with the carbon may complementor supplement electrically generated heat.

[1346]FIG. 96 depicts an embodiment of a elongated member heat source.Elongated members 1342 are removable from opening 544 in the formation.

[1347] In a heat source embodiment, a bare metal elongated member may beformed in a “U” shape (or hairpin) and the member may be suspended froma wellhead or from a positioner placed at or near an interface betweenthe overburden and the formation to be heated. In certain embodiments,the bare metal heaters are formed of rod stock. Cylindrical, highalumina ceramic electrical insulators may be placed over legs of theelongated members. Tack welds along lengths of the legs may fix theposition of the insulators. The insulators may inhibit the elongatedmember from contacting the formation or a well casing (if the elongatedmember is placed within a well casing). The insulators may also inhibitlegs of the “U” shaped members from contacting each other. High aluminaceramic electrical insulators may be purchased from Cooper Industries(Houston, Tex.). In an embodiment, the “U” shaped member may be formedof different metals having different cross-sectional areas so that theelongated members may be relatively long and may dissipate a desiredamount of heat per unit length along the entire length of the elongatedmember.

[1348] Use of welded together sections may result in an elongated memberthat has large diameter sections near a top of the elongated member anda smaller diameter section or sections lower down a length of theelongated member. For example, an embodiment of an elongated member hastwo ⅞ inch (2.2 cm) diameter first sections, two ½ inch (1.3 cm) middlesections, and a ⅜ inch (0.95 cm) diameter bottom section that is bentinto a “U” shape. The elongated member may be made of materials withother cross-sectional shapes such as ovals, squares, rectangles,triangles, etc. The sections may be formed of alloys that will result insubstantially the same heat dissipation per unit length for eachsection.

[1349] In some embodiments, the cross-sectional area and/or the metalused for a particular section may be chosen so that a particular sectionprovides greater (or lesser) heat dissipation per unit length than anadjacent section. More heat dissipation per unit length may be providednear an interface between a hydrocarbon layer and a non-hydrocarbonlayer (e.g., the overburden and the hydrocarbon layer) to counteract endeffects and allow for more uniform heat dissipation into the hydrocarboncontaining formation. A higher heat dissipation per unit length may alsooccur at a lower end of an elongated member to counteract end effectsand allow for more uniform heat dissipation.

[1350] In certain embodiments, the wall thickness of portions of aconductor, or any electrically-conducting portion of a heater, may beadjusted to provide more or less heat to certain zones of a formation.In an embodiment, the wall thickness of a portion of the conductoradjacent to a lean zone (i.e., zone containing relatively little or nohydrocarbons) may be thicker than a portion of the conductor adjacent toa rich zone (i.e., hydrocarbon layer in which hydrocarbons are pyrolyzedand/or produced). Adjusting the wall thickness of a conductor to provideless heat to the lean zone and more heat to the rich zone may moreefficiently use electricity to heat the formation.

[1351]FIG. 97 illustrates a cross-sectional representation of anembodiment of a heater using two oxidizers. One or more oxidizers may beused to heat a hydrocarbon layer or hydrocarbon layers of a formationhaving a relatively shallow depth (e.g., less than about 250 m). Conduit1352 may be placed in opening 544 in a formation. Conduit 1352 may haveupper portion 1354. Upper portion 1354 of conduit 1352 may be placedprimarily in overburden 524 of the formation. A portion of conduit 1352may include high temperature resistant, non-corrosive materials (e.g.,316 stainless steel and/or 304 stainless steel). Upper portion 1354 ofconduit 1352 may include a less temperature resistant material (e.g.,carbon steel). A diameter of opening 544 and conduit 1352 may be chosensuch that a cross-sectional area of opening 544 outside of conduit 1352is approximately equal to a cross-sectional area inside conduit 1352.This may equalize pressures outside and inside conduit 1352. In anembodiment, conduit 1352 has a diameter of about 0.11 m and opening 544has a diameter of about 0.15 m.

[1352] Oxidizing fluid source 1094 may provide oxidizing fluid 1096 intoconduit 1352. Oxidizing fluid 1096 may include hydrogen peroxide, air,oxygen, or oxygen enriched air. In an embodiment, oxidizing fluid source1094 may include a membrane system that enriches air by preferentiallypassing oxygen, instead of nitrogen, through a membrane or membranes.First fuel source 1356 may provide fuel 1358 into first fuel conduit1360. First fuel conduit 1360 may be placed in upper portion 1354 ofconduit 1352. In some embodiments, first fuel conduit 1360 may be placedoutside conduit 1352. In other embodiments, conduit 1352 may be placedwithin first fuel conduit 1360. Fuel 1358 may include combustiblematerial, including but not limited to, hydrogen, methane, ethane, otherhydrocarbon fluids, and/or combinations thereof. Fuel 1358 may includesteam to inhibit coking within the fuel conduit or proximate anoxidizer. First oxidizer 1362 may be placed in conduit 1352 at a lowerend of upper portion 1354. First oxidizer 1362 may oxidize at least aportion of fuel 1358 from first fuel conduit 1360 with at least aportion of oxidizing fluid 1096. First oxidizer may be a burner such asan inline burner. Burners may be obtained from John Zink Company (Tulsa,Okla.) or Callidus Technologies (Tulsa, Okla.). First oxidizer 1362 mayinclude an ignition source such as a flame. First oxidizer 1362 may alsoinclude a flameless ignition source such as, for example, an electricigniter.

[1353] In some embodiments, fuel 1358 and oxidizing fluid 1096 may becombined at the surface and provided to opening 544 through conduit1352. Fuel 1358 and oxidizing fluid 1096 may be combined in a mixer,aerator, nozzle, or similar mixing device located at the surface. Insuch an embodiment, conduit 1352 provides both fuel 1358 and oxidizingfluid 1096 into opening 544. Locating first oxidizer 1362 at orproximate the upper portion of the section of the formation to be heatedmay tend to inhibit or decrease coking in one or more of the fuelconduits (e.g., in first fuel conduit 1360).

[1354] Oxidation of fuel 1358 at first oxidizer 1362 will generate heat.The generated heat may heat fluids in a region proximate first oxidizer1362. The heated fluids may include fuel, oxidizing fluid, and oxidationproduct. The heated fluids may be allowed to transfer heat tohydrocarbon layer 522 along a length of conduit 1352. The amount of heattransferred from the heated fluids to the formation may vary dependingon, for example, a temperature of the heated fluids. In general, thegreater the temperature of the heated fluids, the more heat that will betransferred to the formation. In addition, as heat is transferred fromthe heated fluids, the temperature of the heated fluids decreases. Forexample, temperatures of fluids in the oxidizer flame may be about 1300°C. or above, and as the fluids reach a distance of about 150 m from theoxidizer, temperatures of fluids may be, for example, about 750° C.Thus, the temperature of the heated fluids, and hence the heattransferred to the formation, decreases as the heated fluids flow awayfrom the oxidizer.

[1355] First insulation 1364 may be placed on lengths of conduit 1352proximate a region of first oxidizer 1362. First insulation 1364 mayhave a length of about 10 m to about 200 m (e.g., about 50 m). Inalternative embodiments, first insulation 1364 may have a length that isabout 10-40% of the length of conduit 1352 between any two oxidizers(e.g., between first oxidizer 1362 and second oxidizer 1366 in FIG. 97).A length of first insulation 1364 may vary depending on, for example,desired heat transfer rate to the formation, desired temperatureproximate the first oxidizer, and/or desired temperature profile alongthe length of conduit 1352. First insulation 1364 may have a thicknessthat varies (either continually or in step fashion) along its length. Incertain embodiments, first insulation 1364 may have a greater thicknessproximate first oxidizer 1362 and a reduced thickness at a desireddistance from the first oxidizer. The greater thickness of firstinsulation 1364 may preferentially reduce heat transfer proximate firstoxidizer 1362 as compared to a reduced thickness portion of theinsulation. Variable thickness insulation may allow for uniform orrelatively uniform heating of the formation adjacent to a heated portionof the heat source. In an embodiment, first insulation 1364 may have athickness of about 0.03 m proximate first oxidizer 1362 and a thicknessof about 0.015 m at a distance of about 10 m from the first oxidizer. Inthe embodiment, the heated portion of the conduit is about 300 m inlength, with insulation (first insulation 1364) being placed proximatethe upper 100 m portion of this length, and insulation (secondinsulation 1368) being placed proximate the lower 100 m portion of thislength.

[1356] A thickness of first insulation 1364 may vary depending on, forexample, a desired heating rate or a desired temperature within opening544 of hydrocarbon layer 522. The first insulation may inhibit thetransfer of heat from the heated fluids to the formation in a regionproximate the insulating conduit. First insulation 1364 may also inhibitcharring and/or coking of hydrocarbons proximate first oxidizer 1362.First insulation 1364 may inhibit charring and/or coking by reducing anamount of heat transferred to the formation proximate the firstoxidizer. First insulation 1364 may inhibit or decrease coking in fuelconduit 1370 when a carbon containing fuel is in the fuel conduit. Firstinsulation 1364 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel®, calcium silicate, Fiberfrax®,insulating refractory cements such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories, etc. The relatively hightemperatures generated at the flame of first oxidizer 1362, which may beabout 1300° C. or greater, may generate sufficient heat to converthydrocarbons proximate the first oxidizer into coke and/or char if noinsulation is provided.

[1357] Heated fluids from conduit 1352 may exit a lower end of theconduit into opening 544. A temperature of the heated fluids may belower proximate the lower end of conduit 1352 than a temperature of theheated fluids proximate first oxidizer 1362. The heated fluids mayreturn to a surface of the formation through the annulus of opening 544(exhaust annulus 1372) and/or through exhaust conduit 1374. The heatedfluids exiting the formation through exhaust conduit 1374 may bereferred to as exhaust fluids. The exhaust fluids may be allowed tothermally contact conduit 1352 so as to exchange heat between exhaustfluids and either oxidizing fluid or fuel within conduit 1352. Thisexchange of heat may preheat fluids within conduit 1352. Thus, thethermal efficiency of the downhole combustor may be enhanced to as muchas 90% or more (i.e., 90% or more of the heat from the heat ofcombustion is being transferred to a selected section of the formation).

[1358] In certain embodiments, extra oxidizers may be used in additionto oxidizer 1362 and oxidizer 1366 shown in FIG. 97. For example, insome embodiments, one or more extra oxidizers may be placed betweenoxidizer 1362 and oxidizer 1366. Such extra oxidizers may be, forexample, placed at intervals of about 20-50 m. In certain embodiments,one oxidizer (e.g., oxidizer 1362) may provide at least about 50% of theheat to the selected section of the formation, and the other oxidizersmay be used to adjust the heat flux along the length of the oxidizer.

[1359] In some embodiments, fins may be placed on an outside surface ofconduit 1352 to increase exchange of heat between exhaust fluids andfluids within the conduit. Exhaust conduit 1374 may extend into opening544. A position of lower end of exhaust conduit 1374 may vary dependingon, for example, a desired removal rate of exhaust fluids from theopening. In certain embodiments, it may be advantageous to remove fluidsthrough exhaust conduit 1374 from a lower portion of opening 544 ratherthan allowing exhaust fluids to return to the surface through theannulus of the opening. All or part of the exhaust fluids may be vented,treated in a treatment facility, and/or recycled. In some circumstances,the exhaust fluids may be recycled as a portion of fuel 1358 oroxidizing fluid 1096 or recycled into an additional heater in anotherportion of the formation.

[1360] Two or more heater wells with oxidizers may be coupled in serieswith exhaust fluids from a first heater well being used as a portion offuel for a second heater well. Exhaust fluids from the second heaterwell may be used as a portion of fuel for a third heater well, and so onas needed. In some embodiments, a separator may separate unused fueland/or oxidizer from combustion products to increase the energy contentof the fuel for the next oxidizer. Using the heated exhaust fluids as aportion of the feed for a heater well may decrease costs associated withpressurizing fluids for use in the heater well. In an embodiment, aportion (e.g., about one-third or about one-half) of the oxygen in theoxidizing fluid stream provided to a first heater well may be utilizedin the first heater well. This would leave the remaining oxygenavailable for use as oxidizing fluid for subsequent heater wells. Theheated exhaust fluids tend to have a pressure associated with theprevious heater well and may be maintained at that pressure forproviding to the next heater well. Thus, connection of two or moreheater wells in series can significantly reduce compression costsassociated with pressurizing fluids.

[1361] Overburden casing 1120 and reinforcing material 1122 may beplaced in overburden 524. Overburden 524 may be above hydrocarbon layer522. In certain embodiments, overburden casing 1120 may extend downwardinto part or the entire zone being heated. Overburden casing 1120 mayinclude steel (e.g., carbon steel or stainless steel). Reinforcingmaterial 1122 may include, for example, foamed cement or a cement withglass and/or ceramic beads filled with air.

[1362] As depicted in the embodiment of FIG. 97, a heater may havesecond fuel conduit 1370. Second fuel conduit 1370 may be coupled toconduit 1352. Second fuel source 1376 may provide fuel 1358 to secondfuel conduit 1370. Second fuel source 1376 may provide fuel that issimilar to fuel from first fuel source 1356. In some embodiments, fuelfrom second fuel source 1376 may be different than fuel from first fuelsource 1356. Fuel 1358 may exit second fuel conduit 1370 at a locationproximate second oxidizer 1366. Second oxidizer 1366 may be locatedproximate a bottom of conduit 1352 and/or opening 544. Second oxidizer1366 may be coupled to a lower end of second fuel conduit 1370. Secondoxidizer 1366 may be used to oxidize at least a portion of fuel 1358(exiting second fuel conduit 1370) with heated fluids exiting conduit1352. Un-oxidized portions of heated fluids from conduit 1352 may alsobe oxidized at second oxidizer 1366. Second oxidizer 1366 may be aburner (e.g., a ring burner). Second oxidizer 1366 may be made ofstainless steel. Second oxidizer 1366 may include one or more orificesthat allow a flow of fuel 1358 into opening 544. The one or moreorifices may be critical flow orifices. Oxidized portions of fuel 1358,along with un-oxidized portions of fuel, may combine with heated fluidsfrom conduit 1352 and exit the formation with the heated fluids. Heatgenerated by oxidation of fuel 1358 from second fuel conduit 1370proximate a lower end of opening 544, in combination with heat generatedfrom heated fluids in conduit 1352, may provide more uniform heating ofhydrocarbon layer 522 than using a single oxidizer. In an embodiment,second oxidizer 1366 may be located about 200 m from first oxidizer1362. However, in some embodiments, second oxidizer 1366 may be locatedup to about 250 m from first oxidizer 1362.

[1363] Heat generated by oxidation of fuel at the first and secondoxidizers may be allowed to transfer to the formation. The generatedheat may transfer to a pyrolysis zone in the formation. Heat transferredto the pyrolysis zone may pyrolyze at least some hydrocarbons within thepyrolysis zone.

[1364] In some embodiments, ignition source 1378 may be disposedproximate a lower end of second fuel conduit 1370 and/or second oxidizer1366. Ignition source 1378 may be an electrically controlled ignitionsource. Ignition source 1378 may be coupled to ignition source lead-inwire 1380. Ignition source lead-in wire 1380 may be further coupled to apower source for ignition source 1378. Ignition source 1378 may be usedto initiate oxidation of fuel 1358 exiting second fuel conduit 1370.After oxidation of fuel 1358 from second fuel conduit 1370 has begun,ignition source 1378 may be turned down and/or off. In otherembodiments, an ignition source may also be disposed proximate firstoxidizer 1362.

[1365] In some embodiments, ignition source 1378 may not be used if, forexample, the conditions in the wellbore are sufficient to auto-ignitefuel 1358 being used. For example, if hydrogen is used as the fuel, thehydrogen will auto-ignite in the wellbore if the temperature andpressure in the wellbore are sufficient for autoignition of the fuel.

[1366] As shown in FIG. 97, second insulation 1368 may be disposed in aregion proximate second oxidizer 1366. Second insulation 1368 may bedisposed on a face of hydrocarbon layer 522 along an inner surface ofopening 544. Second insulation 1368 may have a length of about 10 m toabout 200 m (e.g., about 50 m). A length of second insulation 1368 mayvary, however, depending on, for example, a desired heat transfer rateto the formation, a desired temperature proximate the lower oxidizer, ora desired temperature profile along a length of conduit 1352 and/orhydrocarbon layer 522. In an embodiment, the length of second insulation1368 is about 10-40% of the length of conduit 1352 between any twooxidizers. Second insulation 1368 may have a thickness that varies(either continually or in step fashion) along its length. In certainembodiments, second insulation 1368 may have a larger thicknessproximate second oxidizer 1366 and a reduced thickness at a desireddistance from the second oxidizer. The larger thickness of secondinsulation 1368 may preferentially reduce heat transfer proximate secondoxidizer 1366 as compared to the reduced thickness portion of theinsulation. For example, second insulation 1368 may have a thickness ofabout 0.03 m proximate second oxidizer 1366 and a thickness of about0.015 m at a distance of about 10 m from the second oxidizer.

[1367] A thickness of second insulation 1368 may vary depending on, forexample, a desired heating rate or a desired temperature at a surface ofhydrocarbon layer 522. The second insulation may inhibit the transfer ofheat from the heated fluids to the formation in a region proximate theinsulation. Second insulation 1368 may also inhibit charring and/orcoking of hydrocarbons proximate second oxidizer 1366. Second insulation1368 may inhibit charring and/or coking by reducing an amount of heattransferred to the formation proximate the second oxidizer. Secondinsulation 1368 may be made of a non-corrosive, thermally insulatingmaterial such as rock wool, Nextel™, calcium silicate, Fiberfrax®, orthermally insulating concretes such as those manufactured by HarbizonWalker, A. P. Green, or National Refractories. Hydrogen and/or steam mayalso be added to fuel used in the second oxidizer to further inhibitcoking and/or charring of the formation proximate the second oxidizerand/or fuel within the fuel conduit.

[1368] In other embodiments, one or more additional oxidizers may beplaced in opening 544. The one or more additional oxidizers may be usedto increase a heat output and/or provide more uniform heating of theformation. Additional fuel conduits and/or additional insulatingconduits may be used with the one or more additional oxidizers asneeded.

[1369] In an example using two downhole combustors to heat a portion ofa formation, the formation has a depth for treatment of about 228 m,with an overburden having a depth of about 91.5 m. Two oxidizers areused, as shown in the embodiment of FIG. 97, to provide heat to theformation in an opening with a diameter of about 0.15 m. To equalize thepressure inside the conduit and outside the conduit, a cross-sectionalarea inside the conduit should approximately equal a cross-sectionalarea outside the conduit. Thus, the conduit has a diameter of about 0.11m.

[1370] To heat the formation at a heat input of about 655 watts/meter(W/m), a total heat input of about 150,000 W is needed. About 16,000 Wof heat is generated for every 28 standard liters per minute (slm) ofmethane (CH₄) provided to the burners. Thus, a flow rate of about 270slm is needed to generate the 150,000 W of heat. A temperature midwaybetween the two oxidizers is about 555° C. less than the temperature ata flame of either oxidizer (about 1315° C.). The temperature midwaybetween the two oxidizers on the wall of the formation (where there isno insulation) is about 690° C. About 3,800 W can be carried by 2,830slm of air for every 55° C. of temperature change in the conduit. Thus,for the air to carry half the heat required (about 75,000 W) from thefirst oxidizer to the halfway point, 5,660 slm of air is needed. Theother half of the heat required may be supplied by air passing thesecond oxidizer and carrying heat from the second oxidizer.

[1371] Using air (21% oxygen) as the oxidizing fluid, a flow rate ofabout 5,660 slm of air can be used to provide excess oxygen to eachoxidizer. About half of the oxygen, or about 11% of the air, is used inthe two oxidizers in a first heater well. Thus, the exhaust fluid isessentially air with an oxygen content of about 10%. This exhaust fluidcan be used in a second heater well. Pressure of the incoming air of thefirst heater well is about 6.2 bars absolute. Pressure of the outgoingair of the first heater well is about 4.4 bars absolute. This pressureis also the incoming air pressure of a second heater well. The outletpressure of the second heater well is about 1.7 bars absolute. Thus, theair does not need to be recompressed between the first heater well andthe second heater well.

[1372]FIG. 98 illustrates a cross-sectional representation of anembodiment of a downhole combustor heater for heating a formation. Asdepicted in FIG. 98, electric heater 1132 may be used instead of secondoxidizer 1366 (as shown in FIG. 97) to provide additional heat to aportion of hydrocarbon layer 522.

[1373] In a heat source embodiment, electric heater 1132 may be aninsulated conductor heater. In some embodiments, electric heater 1132may be a conductor-in-conduit heater or an elongated member heater. Ingeneral, electric heaters tend to provide a more controllable and/orpredictable heating profile than combustion heaters. The heat profile ofelectric heater 1132 may be selected to achieve a selected heatingprofile of the formation (e.g., uniform). For example, the heatingprofile of electric heater 1132 may be selected to “mirror” the heatingprofile of oxidizer 1362 such that, when the heat from electric heater1132 and oxidizer 1362 are superpositioned, substantially uniformheating is applied along the length of the conduit.

[1374] In other heat source embodiments, any other type of heater, suchas a natural distributed combustor or flameless distributed combustor,may be used instead of electric heater 1132. In certain embodiments,electric heater 1132 may be used instead of first oxidizer 1362 to heata portion of hydrocarbon layer 522. FIG. 99 depicts an embodiment usinga downhole combustor with a flameless distributed combustor. Second fuelconduit 1370 may have orifices 1098 (e.g., critical flow orifices)distributed along the length of the conduit. Orifices 1098 may bedistributed such that a heating profile along the length of hydrocarbonlayer 522 is substantially uniform. For example, more orifices 1098 maybe placed on second fuel conduit 1370 in a lower portion of the conduitthan in an upper portion of the conduit. This will provide more heatingto a portion of hydrocarbon layer 522 that is farther from firstoxidizer 1362.

[1375] As depicted in FIG. 98, electric heater 1132 may be placed inopening 544 proximate conduit 1352. Electric heater 1132 may be used toprovide heat to hydrocarbon layer 522 in a portion of opening 544proximate a lower end of conduit 1352. Electric heater 1132 may becoupled to lead-in conductor 1146. Using electric heater 1132 as well asheated fluids from conduit 1352 to heat hydrocarbon layer 522 mayprovide substantially uniform heating of hydrocarbon layer 522.

[1376]FIG. 100 illustrates a cross-sectional representation of anembodiment of a multilateral downhole combustor heater. Hydrocarbonlayer 522 may be a relatively thin layer (e.g., with a thickness of lessthan about 10 m, about 30 m, or about 60 m) selected for treatment. Suchlayers may exist in, but are not limited to, tar sands, oil shale, orcoal formations. Opening 544 may extend below overburden 524 and thendiverge in more than one direction within hydrocarbon layer 522. Opening544 may have walls that are substantially parallel to upper and lowersurfaces of hydrocarbon layer 522.

[1377] Conduit 1352 may extend substantially vertically into opening 544as depicted in FIG. 100. First oxidizer 1362 may be placed in orproximate conduit 1352. Oxidizing fluid 1096 may be provided to firstoxidizer 1362 through conduit 1352. First fuel conduit 1360 may be usedto provide fuel 1358 to first oxidizer 1362. Second conduit 1381 may becoupled to conduit 1352. Second conduit 1381 may be orientedsubstantially perpendicular to conduit 1352. Third conduit 1382 may alsobe coupled to conduit 1352. Third conduit 1382 may be orientedsubstantially perpendicular to conduit 1352. Second oxidizer 1366 may beplaced at an end of second conduit 1381. Second oxidizer 1366 may be aring burner. Third oxidizer 1384 may be placed at an end of thirdconduit 1382. In an embodiment, third oxidizer 1384 is a ring burner.Second oxidizer 1366 and third oxidizer 1384 may be placed at or nearopposite ends of opening 544.

[1378] Second fuel conduit 1370 may be used to provide fuel to secondoxidizer 1366. Third fuel conduit 1386 may be used to provide fuel tothird oxidizer 1384. Oxidizing fluid 1096 may be provided to secondoxidizer 1366 through conduit 1352 and second conduit 1381. Oxidizingfluid 1096 may be provided to third oxidizer 1384 through conduit 1352and third conduit 1382. First insulation 1364 may be placed proximatefirst oxidizer 1362. Second insulation 1368 and third insulation 1387may be placed proximate second oxidizer 1366 and third oxidizer 1384,respectively. Second oxidizer 1366 and third oxidizer 1384 may belocated up to about 175 m from first conduit 1352. In some embodiments,a distance between second oxidizer 1366 or third oxidizer 1384 and firstconduit 1352 may be less, depending on heating requirements ofhydrocarbon layer 522. Heat provided by oxidation of fuel at firstoxidizer 1362, second oxidizer 1366, and third oxidizer 1384 may allowfor substantially uniform heating of hydrocarbon layer 522.

[1379] Exhaust fluids may be removed through opening 544. The exhaustfluids may exchange heat with fluids entering opening 544 throughconduit 1352. Exhaust fluids may also be used in additional heater wellsand/or treated in treatment facilities.

[1380] In a heat source embodiment, one or more electric heaters may beused instead of, or in combination with, first oxidizer 1362, secondoxidizer 1366, and/or third oxidizer 1384 to provide heat to hydrocarbonlayer 522. Using electric heaters in combination with oxidizers mayprovide for substantially uniform heating of hydrocarbon layer 522.

[1381]FIG. 101 depicts a heat source embodiment in which one or moreoxidizers are placed in first conduit 1388 and second conduit 1390 toprovide heat to hydrocarbon layer 522. The embodiment may be used toheat a relatively thin formation. First oxidizer 1362 may be placed infirst conduit 1388. A second oxidizer 1366 may be placed proximate anend of first conduit 1388. First fuel conduit 1360 may provide fuel tofirst oxidizer 1362. Second fuel conduit 1370 may provide fuel to secondoxidizer 1366. First insulation 1364 may be placed proximate firstoxidizer 1362. Oxidizing fluid 1096 may be provided into first conduit1388. A portion of oxidizing fluid 1096 may be used to oxidize fuel atfirst oxidizer 1362. Second insulation 1368 may be placed proximatesecond oxidizer 1366.

[1382] Second conduit 1390 may diverge in an opposite direction fromfirst conduit 1388 in opening 544 and substantially mirror first conduit1388. Second conduit 1390 may include elements similar to the elementsof first conduit 1388, such as first oxidizer 1362, first fuel conduit1360, first insulation 1364, second oxidizer 1366, second fuel conduit1370, and/or second insulation 1368. These elements may be used tosubstantially uniformly heat hydrocarbon layer 522 below overburden 524along lengths of conduits 1388 and 1390.

[1383]FIG. 102 illustrates a cross-sectional representation of anembodiment of a downhole combustor for heating a formation. Opening 544is a single opening within hydrocarbon layer 522 that may have first end1114 and second end 1116. Oxidizers 1362 may be placed in opening 544proximate a junction of overburden 524 and hydrocarbon layer 522 atfirst end 1114 and second end 1116. Insulation 1368 may be placedproximate each oxidizer 1362. Fuel conduit 1360 may be used to providefuel 1358 from fuel source 1356 to oxidizer 1362. Oxidizing fluid 1096may be provided into opening 544 from oxidizing fluid source 1094through conduit 1352. Casing 550 may be placed in opening 544. Casing550 may be made of carbon steel. Portions of casing 550 that may besubjected to much higher temperatures (e.g., proximate oxidizers 1362)may include stainless steel or other high temperature, corrosionresistant metal. In some embodiments, casing 550 may extend intoportions of opening 544 within overburden 524.

[1384] In a heat source embodiment, oxidizing fluid 1096 and fuel 1358are provided to oxidizer 1362 in first end 1114. Heated fluids fromoxidizer 1362 in first end 1114 tend to flow through opening 544 towardssecond end 1116. Heat may transfer from the heated fluids to hydrocarbonlayer 522 along a length of opening 544. The heated fluids may beremoved from the formation through second end 1116. During this time,oxidizer 1362 at second end 1116 may be turned off. The removed fluidsmay be provided to a second opening in the formation and used asoxidizing fluid and/or fuel in the second opening. After a selected time(e.g., about a week), oxidizer 1362 at first end 1114 may be turned off.At this time, oxidizing fluid 1096 and fuel 1358 may be provided tooxidizer 1362 at second end 1116 and the oxidizer turned on. Heatedfluids may be removed during this time through first end 1114. Oxidizers1362 at first end 1114 and at second end 1116 may be used alternatelyfor selected times (e.g., about a week) to heat hydrocarbon layer 522.This may provide a more substantially uniform heating profile ofhydrocarbon layer 522. Removing the heated fluids from the openingthrough an end distant from an oxidizer may reduce a possibility ofcoking within opening 544 as heated fluids are removed from the openingseparately from incoming fluids. The use of the heat content of anoxidizing fluid may also be more efficient as the heated fluids can beused in a second opening or second downhole combustor.

[1385]FIG. 102A depicts an embodiment of a heat source for a hydrocarboncontaining formation. Fuel conduit 1360 may be placed within opening544. In some embodiments, opening 544 may include casing 550. Opening544 is a single opening within the formation that may have first end1114 at a first location on the surface of the earth and second end 1116at a second location on the surface of the earth. Oxidizers 1362 may bepositioned proximate the fuel conduit in hydrocarbon layer 522.Oxidizers 1362 may be separated by a distance ranging from about 3 m toabout 50 m (e.g., about 30 m). Fuel 1358 may be provided to fuel conduit1360. In addition, steam 1392 may be provided to fuel conduit 1360 toreduce coking proximate oxidizers 1362 and/or in fuel conduit 1360.Oxidizing fluid 1096 (e.g., air and/or oxygen) may be provided tooxidizers 1362 through opening 544. Oxidation of fuel 1358 may generateheat. The heat may transfer to a portion of the formation. Oxidationproduct 1102 may exit opening 544 proximate second end 1116.

[1386]FIG. 103 depicts a schematic, from an elevated view, of anembodiment for using downhole combustors depicted in the embodiment ofFIG. 102. In some embodiments, the schematic depicted in FIG. 103, andvariations of the schematic, may be used for other types of heaters(e.g., surface burners, flameless distributed combustors, etc.) that mayutilize fuel fluid and/or oxidizing fluid in one or more openings in ahydrocarbon containing formation. Openings 1394, 1396, 1398, 1400, 1402,and 1404 may have downhole combustors (as shown in the embodiment ofFIG. 102) placed in each opening. More or fewer openings (i.e., openingswith a downhole combustor) may be used as needed. A number of openingsmay depend on, for example, a size of an area for treatment, a desiredheating rate, or a selected well spacing. Conduit 1406 may be used totransport fluids from a downhole combustor in opening 1394 to downholecombustors in openings 1396, 1398, 1400, 1402, and 1404. The openingsmay be coupled in series using conduit 1406. Compressor 1408 may be usedbetween openings, as needed, to increase a pressure of fluid between theopenings. Additional oxidizing fluid may be provided to each compressor1408 from conduit 1410. A selected flow of fuel from a fuel source maybe provided into each of the openings.

[1387] For a selected time, a flow of fluids may be from first opening1394 towards opening 1404. Flow of fluid within first opening 1394 maybe substantially opposite flow within second opening 1396. Subsequently,flow within second opening 1396 may be substantially opposite flowwithin third opening 1398, etc. This may provide substantially moreuniform heating of the formation using the downhole combustors withineach opening. After the selected time, the flow of fluids may bereversed to flow from opening 1404 towards first opening 1394. Thisprocess may be repeated as needed during a time needed for treatment ofthe formation. Alternating the flow of fluids may enhance the uniformityof a heating profile of the formation.

[1388]FIG. 104 depicts a schematic representation of an embodiment of aheater well positioned within a hydrocarbon containing formation. Heaterwell 520 may be placed within opening 544. In certain embodiments,opening 544 is a single opening within the formation that may have firstend 1114 and second end 1116 contacting the surface of the earth.Opening 544 may include elongated portions 1412, 1414, 1416. Elongatedportions 1412, 1416 may be placed substantially in a non-hydrocarboncontaining layer (e.g., overburden). Elongated portion 1414 may beplaced substantially within hydrocarbon layer 522 and/or a treatmentzone.

[1389] In some heat source embodiments, casing 550 may be placed inopening 544. In some embodiments, casing 550 may be made of carbonsteel. Portions of casing 550 that may be subjected to high temperaturesmay be made of more temperature resistant material (e.g., stainlesssteel). In some embodiments, casing 550 may extend into elongatedportions 1412, 1416 within overburden 524. Oxidizers 1362, 1366 may beplaced proximate a junction of overburden 524 and hydrocarbon layer 522at first end 1114 and second end 1116 of opening 544. Oxidizers 1362,1366 may include burners (e.g., inline burners and/or ring burners).Insulation 1368 may be placed proximate each oxidizer 1362, 1366.

[1390] Conduit 1418 may be placed within opening 544 forming annulus1420 between an outer surface of conduit 1418 and an inner surface ofthe casing 550. Annulus 1420 may have a regular and/or irregular shapewithin the opening. In some embodiments, oxidizers may be positionedwithin the annulus and/or the conduit to provide heat to a portion ofthe formation. Oxidizer 1362 is positioned within annulus 1420 and mayinclude a ring burner. Heated fluids from oxidizer 1362 may flow withinannulus 1420 to end 1116. Heated fluids from oxidizer 1366 may bedirected by conduit 1418 through opening 544. Heated fluids may include,but are not limited to oxidation product, oxidizing fluid, and/or fuel.Flow of the heated fluids through annulus 1420 may be in the oppositedirection of the flow of heated fluids in conduit 1418. In someembodiments, oxidizers 1362, 1366 may be positioned proximate the sameend of opening 544 to allow the heated fluids to flow through opening544 in the same direction.

[1391] Fuel conduits 1360 may be used to provide fuel 1358 from fuelsource 1356 to oxidizers 1362, 1366. Oxidizing fluid 1096 may beprovided to oxidizers 1362, 1366 from oxidizing fluid source 1094through conduits 1352. Flow of fuel 1358 and oxidizing fluid 1096 maygenerate oxidation products at oxidizers 1362, 1366. In someembodiments, a flow of oxidizing fluid 1096 may be controlled to controloxidation at oxidizers 1362, 1366. Alternatively, a flow of fuel may becontrolled to control oxidation at oxidizers 1362, 1366.

[1392] In a heat source embodiment, oxidizing fluid 1096 and fuel 1358are provided to oxidizer 1362. Heated fluids from oxidizer 1362 in firstend 1114 tend to flow through opening 544 towards second end 1116. Heatmay transfer from the heated fluids to hydrocarbon layer 522 along asegment of opening 544. The heated fluids may be removed from theformation through second end 1116. In some embodiments, a portion of theheated fluids removed from the formation may be provided to fuel conduit1360 at end 1116 to be utilized as fuel in oxidizer 1366. Fluids heatedby oxidizer 1366 may be directed through the opening in conduit 1418 tofirst end 1114. In some embodiments, a portion of the heated fluids isprovided to fuel conduit 1360 at first end 1114. Alternatively, heatedfluids produced from either end of the opening may be directed to asecond opening in the formation for use as either oxidizing fluid and/orfuel. In some embodiments, heated fluids may be directed toward one endof the opening for use in a single oxidizer.

[1393] Oxidizers 1362, 1366 may be utilized concurrently. In someembodiments, use of the oxidizers may alternate. Oxidizer 1362 may beturned off after a selected time period (e.g., about a week). At thistime, oxidizing fluid 1096 and fuel 1358 may be provided to oxidizer1366. Heated fluids may be removed during this time through first end1114. Use of oxidizer 1362 and oxidizer 1366 may be alternated forselected times to heat hydrocarbon layer 522. Flowing oxidizing fluidsin opposite directions may produce a more uniform heating profile inhydrocarbon layer 522. Removing the heated fluids from the openingthrough an end distant from the oxidizer at which the heated fluids wereproduced may reduce the possibility for coking within the opening.Heated fluids may be removed from the formation in exhaust conduits insome embodiments. In addition, the potential for coking may be furtherreduced by removing heated fluids from the opening separately fromincoming fluids (e.g., fuel and/or oxidizing fluid). In certaininstances, some heat within the heated fluids may transfer to theincoming fluids to increase the efficiency of the oxidizers.

[1394]FIG. 105 depicts an embodiment of a heat source positioned withina hydrocarbon containing formation. Surface units 1422 (e.g., burnersand/or furnaces) provide heat to an opening in the formation. Surfaceunit 1422 may provide heat to conduit 1418 positioned in conduit 1424.Surface unit 1422 positioned proximate first end 1114 of opening 544 mayheat fluids 1426 (e.g., air, oxygen, steam, fuel, and/or flue gas)provided to surface unit 1422. Conduit 1418 may extend into surface unit1422 to allow fluids heated in surface unit 1422 proximate first end1114 to flow into conduit 1418. Conduit 1418 may direct fluid flow tosecond end 1116. At second end 1116 conduit 1418 may provide fluids tosurface unit 1422. Surface unit 1422 may heat the fluids. The heatedfluids may flow into conduit 1424. Heated fluids may then flow throughconduit 1424 towards end 1114. In some embodiments, conduit 1418 andconduit 1424 may be concentric.

[1395] In some embodiments, fluids may be compressed prior to enteringthe surface unit. Compression of the fluids may maintain a fluid flowthrough the opening. Flow of fluids through the conduits may affect thetransfer of heat from the conduits to the formation.

[1396] In some embodiments, a single surface unit may be utilized forheating proximate first end 1114. Conduits may be positioned such thatfluid within an inner conduit flows into the annulus between the innerconduit and an outer conduit. Thus the fluid flow in the inner conduitand the annulus may be counter current.

[1397] A heat source embodiment is illustrated in FIG. 106. Conduits1418, 1424 may be placed within opening 544. Opening 544 may be an openwellbore. In some embodiments, a casing may be included in a portion ofthe opening (e.g., in the portion in the overburden). In addition, someembodiments may include insulation surrounding a portion of conduits1418, 1424. For example, the portions of the conduits within overburden524 may be insulated to inhibit heat transfer from the heated fluids tothe overburden and/or a portion of the formation proximate theoxidizers.

[1398]FIG. 107 illustrates an embodiment of a surface combustor that mayheat a section of a hydrocarbon containing formation. Fuel fluid 1428may be provided into burner 1430 through conduit 1406. An oxidizingfluid may be provided into burner 1430 from oxidizing fluid source 1094.Fuel fluid 1428 may be oxidized with the oxidizing fluid in burner 1430to form oxidation product 1102. Fuel fluid 1428 may include, but is notlimited to, hydrogen, methane, ethane, and/or other hydrocarbons. Burner1430 may be located external to the formation or within opening 544 inhydrocarbon layer 522. Source 1432 may heat fuel fluid 1428 to atemperature sufficient to support oxidation in burner 1430. Source 1432may heat fuel fluid 1428 to a temperature of about 1425° C. Source 1432may be coupled to an end of conduit 1406. In a heat source embodiment,source 1432 is a pilot flame. The pilot flame may burn with a small flowof fuel fluid 1428. In other embodiments, source 1432 may be anelectrical ignition source.

[1399] Oxidation product 1102 may be provided into opening 544 withininner conduit 1092 coupled to burner 1430. Heat may be transferred fromoxidation product 1102 through outer conduit 1090 into opening 544 andto hydrocarbon layer 522 along a length of inner conduit 1092. Oxidationproduct 1102 may cool along the length of inner conduit 1092. Forexample, oxidation product 1102 may have a temperature of about 870° C.proximate top of inner conduit 1092 and a temperature of about 650° C.proximate bottom of inner conduit 1092. A section of inner conduit 1092proximate burner 1430 may have ceramic insulator 1434 disposed on aninner surface of inner conduit 1092. Ceramic insulator 1434 may inhibitmelting of inner conduit 1092 and/or insulation 1436 proximate burner1430. Opening 544 may extend into the formation a length up to about 550m below surface 542.

[1400] Inner conduit 1092 may provide oxidation product 1102 into outerconduit 1090 proximate a bottom of opening 544. Inner conduit 1092 mayhave insulation 1436. FIG. 108 illustrates an embodiment of innerconduit 1092 with insulation 1436 and ceramic insulator 1434 disposed onan inner surface of inner conduit 1092. Insulation 1436 may inhibit heattransfer between fluids in inner conduit 1092 and fluids in outerconduit 1090. A thickness of insulation 1436 may be varied along alength of inner conduit 1092 such that heat transfer to hydrocarbonlayer 522 may vary along the length of inner conduit 1092. For example,a thickness of insulation 1436 may be tapered from a larger thickness toa lesser thickness from a top portion to a bottom portion, respectively,of inner conduit 1092 in opening 544. Such a tapered thickness mayprovide more uniform heating of hydrocarbon layer 522 along the lengthof inner conduit 1092 in opening 544. Insulation 1436 may includeceramic and metal materials. Oxidation product 1102 may return tosurface 542 through outer conduit 1090. Outer conduit 1090 may haveinsulation 1438, as depicted in FIG. 107. Insulation 1438 may inhibitheat transfer from outer conduit 1090 to overburden 524.

[1401] Oxidation product 1102 may be provided to an additional burnerthrough conduit 1410 at surface 542. Oxidation product 1102 may be usedas a portion of a fuel fluid in the additional burner. Doing so mayincrease an efficiency of energy output versus energy input for heatinghydrocarbon layer 522. The additional burner may provide heat through anadditional opening in hydrocarbon layer 522.

[1402] In some embodiments, an electric heater may provide heat inaddition to heat provided from a surface combustor. The electric heatermay be, for example, an insulated conductor heater or aconductor-in-conduit heater as described in any of the aboveembodiments. The electric heater may provide the additional heat to ahydrocarbon containing formation so that the hydrocarbon containingformation is heated substantially uniformly along a depth of an openingin the formation.

[1403] Flameless combustors such as those described in U.S. Pat. No.5,404,952 to Vinegar et al., which is incorporated by reference as iffully set forth herein, may heat a hydrocarbon containing formation.

[1404]FIG. 109 illustrates an embodiment of a flameless combustor thatmay heat a section of the hydrocarbon containing formation. Theflameless combustor may include center tube 1440 disposed within innerconduit 1092. Center tube 1440 and inner conduit 1092 may be placedwithin outer conduit 1090. Outer conduit 1090 may be disposed withinopening 544 in hydrocarbon layer 522. Fuel fluid 1428 may be providedinto the flameless combustor through center tube 1440. If a hydrocarbonfuel such as methane is utilized, the fuel may be mixed with steam toinhibit coking in center tube 1440. If hydrogen is used as the fuel, nosteam may be required.

[1405] Center tube 1440 may include flow mechanisms 1442 (e.g., floworifices) disposed within an oxidation region to allow a flow of fuelfluid 1428 into inner conduit 1092. Flow mechanisms 1442 may control aflow of fuel fluid 1428 into inner conduit 1092 such that the flow offuel fluid 1428 is not dependent on a pressure in inner conduit 1092.Oxidizing fluid 1096 may be provided into the combustor through innerconduit 1092. Oxidizing fluid 1096 may be provided from oxidizing fluidsource 1094. Flow mechanisms 1442 on center tube 1440 may inhibit flowof oxidizing fluid 1096 into center tube 1440.

[1406] Oxidizing fluid 1096 may mix with fuel fluid 1428 in theoxidation region of inner conduit 1092. Either oxidizing fluid 1096 orfuel fluid 1428, or a combination of both, may be preheated external tothe combustor to a temperature sufficient to support oxidation of fuelfluid 1428. Oxidation of fuel fluid 1428 may provide heat generationwithin outer conduit 1090. The generated heat may provide heat to aportion of a hydrocarbon containing formation proximate the oxidationregion of inner conduit 1092. Products 1444 from oxidation of fuel fluid1428 may be removed through outer conduit 1090 outside inner conduit1092. Heat exchange between the downgoing oxidizing fluid and theupgoing combustion products in the overburden results in enhancedthermal efficiency. A flow of removed combustion products 1444 may bebalanced with a flow of fuel fluid 1428 and oxidizing fluid 1096 tomaintain a temperature above auto-ignition temperature but below atemperature sufficient to produce oxides of nitrogen. In addition, aconstant flow of fluids may provide a substantially uniform temperaturedistribution within the oxidation region of inner conduit 1092. Outerconduit 1090 may be a stainless steel tube. Heating in the portion ofthe hydrocarbon containing formation may be substantially uniform.Maintaining a temperature below temperatures sufficient to produceoxides of nitrogen may allow for relatively inexpensive metallurgicalcost.

[1407] Care may be taken during design and installation of a well (e.g.,freeze wells, production wells, monitoring wells, and heat sources) intoa formation to allow for thermal effects within the formation. Heatingand/or cooling of the formation may expand and/or contract elements of awell, such as the well casing. Elements of a well may expand or contractat different rates (e.g., due to different thermal expansioncoefficients). Thermal expansion or contraction may cause failures (suchas leaks, fractures, short-circuiting, etc.) to occur in a well. Anoperational lifetime of one or more elements in the wellbore may beshortened by such failures.

[1408] In some well embodiments, a portion of the well is an openwellbore completion. Portions of the well may be suspended from awellbore or a casing that is cemented in the formation (e.g., a portionof a well in the overburden). Expansion of the well due to heat may beaccommodated in the open wellbore portion of the well.

[1409] In a well embodiment, an expansion mechanism may be coupled to aheat source or other element of a well placed in an opening in aformation. The expansion mechanism may allow for thermal expansion ofthe heat source or element during use. The expansion mechanism may beused to absorb changes in length of the well as the well expands orcontracts with temperature. The expansion mechanism may inhibit the heatsource or element from being pushed out of the opening during thermalexpansion. Using the expansion mechanism in the opening may increase anoperational lifetime of the well.

[1410]FIG. 110 illustrates a representation of an embodiment ofexpansion mechanism 1238 coupled to heat source 508 in opening 544 inhydrocarbon layer 522. Expansion mechanism 1238 may allow for thermalexpansion of heat source 508. Heat source 508 may be any heat source(e.g., conductor-in-conduit heat source, insulated conductor heatsource, natural distributed combustor heat source, etc.). In someembodiments, more than one expansion mechanism 1238 may be coupled toindividual components of a heat source. For example, if the heat sourceincludes more than one element (e.g., conductors, conduits, supports,cables, elongated members, etc.), an expansion mechanism may be coupledto each element. Expansion mechanism 1238 may include spring loading. Inone embodiment, expansion mechanism 1238 is an accordion mechanism. Inanother embodiment, expansion mechanism 1238 is a bellows or anexpansion joint.

[1411] Expansion mechanism 1238 may be coupled to heat source 508 at abottom of the heat source in opening 544. In some embodiments, expansionmechanism 1238 may be coupled to heat source 508 at a top of the heatsource. In other embodiments, expansion mechanism 1238 may be placed atany point along the length of heat source 508 (e.g., in a middle of theheat source). Expansion mechanism 1238 may be used to reduce the hangingweight of heat source 508 (i.e., the weight supported by a wellheadcoupled to the heat source). Reducing the hanging weight of heat source508 may reduce creeping of the heat source during heating.

[1412] Certain heat source embodiments may include an operating systemcoupled to a heat source or heat sources by insulated conductors orother types of wiring. The operating system may interface with the heatsource. The operating system may receive a signal (e.g., anelectromagnetic signal) from a heater that is representative of atemperature distribution of the heat source. Additionally, the operatingsystem may control the heat source, either locally or remotely. Forexample, the operating system may alter a temperature of the heat sourceby altering a parameter of equipment coupled to the heat source. Theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

[1413] For some heat source embodiments, a heat source or heat sourcesmay operate without a control and/or operating system. A heat source mayonly require a power supply from a power source such as an electrictransformer. A conductor-in-conduit heater and/or an elongated memberheater may include a heater element formed of a self-regulatingmaterial, such as 304 stainless steel or 316 stainless steel. Powerdissipation and amperage through a heater element made of aself-regulating material decrease as temperature increases, and increaseas temperature decreases due in part to the resistivity properties ofthe material and Ohm's Law. For a substantially constant voltage supplyto a heater element, if the temperature of the heater element increases,the resistance of the element will increase, the amperage through theheater element will decrease, and the power dissipation will decrease;thus forcing the heater element temperature to decrease. On the otherhand, if the temperature of the heater element decreases, the resistanceof the element will decrease, the amperage through the heater elementwill increase, and the power dissipation will increase; thus forcing theheater element temperature to increase. Some metals, such as certaintypes of nichrome, have resistivity curves that decrease with increasingtemperature for certain temperature ranges. Such materials may not becapable of being self-regulating heaters.

[1414] In some heat source embodiments, leakage current of electricheaters may be monitored. For insulated heaters, an increase in leakagecurrent may show deterioration in an insulated conductor heater. Voltagebreakdown in the insulated conductor heater may cause failure of theheat source. In some heat source embodiments, a current and voltageapplied to electric heaters may be monitored. The current and voltagemay be monitored to assess/indicate resistance in a heater element ofthe heat source. The resistance in the heat source may represent atemperature in the heat source since the resistance of the heat sourcemay be known as a function of temperature. In some embodiments, atemperature of a heat source may be monitored with one or morethermocouples placed in or proximate the heat source. In someembodiments, a control system may monitor a parameter of the heatsource. The control system may alter parameters of the heat source toestablish a desired output such as heating rate and/or temperatureincrease.

[1415] In some embodiments, a thermowell may be disposed into an openingin a hydrocarbon containing formation that includes a heat source. Thethermowell may be disposed in an opening that may or may not have acasing. In the opening without a casing, the thermowell may includeappropriate metallurgy and thickness such that corrosion of thethermowell is inhibited. A thermowell and temperature logging process,such as that described in U.S. Pat. No. 4,616,705 issued to Stegemeieret al., which is incorporated by reference as if fully set forth herein,may be used to monitor temperature. Only selected wells may be equippedwith thermowells to avoid expenses associated with installing andoperating temperature monitors at each heat source. Some thermowells maybe placed midway between two heat sources. Some thermowells may beplaced at or close to a center of a well pattern. Some thermowells maybe placed in or adjacent to production wells.

[1416] In an embodiment for treating a hydrocarbon containing formationin situ, an average temperature within a majority of a selected sectionof the formation may be assessed by measuring temperature within awellbore or wellbores. The wellbore may be a production well, heaterwell, or monitoring well. The temperature within a wellbore may bemeasured to monitor and/or determine operating conditions within theselected section of the formation. The measured temperature may be usedas a property for input into a program for controlling production withinthe formation. In certain embodiments, a measured temperature may beused as input for a software executable on a computational system. Insome embodiments, a temperature within a wellbore may be measured usinga moveable thermocouple. The moveable thermocouple may be disposed in aconduit of a heater or heater well. An example of a moveablethermocouple and its use is described in U.S. Pat. No. 4,616,705 toStegemeier et al.

[1417] In some embodiments, more than one thermocouple may be placed ina wellbore to measure the temperature within the wellbore. Thethermocouples may be part of a multiple thermocouple array. Thethermocouples may be located at various depths and/or locations. Themultiple thermocouple array may include a magnesium oxide insulatedsheath or sheaths placed around portions of the thermocouples. Theinsulated sheaths may include corrosion resistant materials. A corrosionresistant material may include, but is not limited to, stainless steels304, 310, 316 or Inconel. Multiple thermocouple arrays may be obtainedfrom Pyrotenax Cables Ltd. (Ontario, Canada) or Idaho Labs (Idaho Falls,Id.). The multiple thermocouple array may be moveable within thewellbore.

[1418] In certain thermocouple embodiments, voltage isolation may beused with a moveable thermocouple placed in a wellbore. FIG. 111illustrates a schematic of thermocouple 1194 placed inside conductor1112. Conductor 1112 may be placed within conduit 1176 of aconductor-in-conduit heat source. Conductor 1112 may be coupled to lowresistance section 1118. Low resistance section 1118 may be placed inoverburden 524. Conduit 1176 may be placed in wellbore 1336.Thermocouple 1194 may be used to measure a temperature within conductor1112 along a length of the conductor in hydrocarbon layer 522.Thermocouple 1194 may include thermocouple wires that are coupled at thesurface to spool 1294 so that the thermocouple is moveable along thelength of conductor 1112 to obtain a temperature profile in the heatedsection. Thermocouple isolation 1446 may be coupled to thermocouple1194. Thermocouple isolation 1446 may be, for example, a transformercoupled thermocouple isolation block available from Watlow ElectricManufacturing Company (St. Louis, Mo.). Alternately, an opticallyisolated thermocouple isolation block may be used. Thermocoupleisolation 1446 may reduce voltages above the thermocouple isolation andat wellhead 1162. High voltages may exist within wellbore 1336 due touse of the electric heat source within the wellbore. The high voltagescan be dangerous for operators or personnel working around wellhead1162. With thermocouple isolation 1446, voltages at wellhead 1162 (e.g.,at spool 1294) may be lowered to safer levels (e.g., about zero orground potential). Thus, using thermocouple isolation 1446 may increasesafety at wellhead 1162.

[1419] In some embodiments, thermocouple isolation 1446 may be usedalong the length of low resistance section 1118. Temperatures within lowresistance section 1118 may not be above a maximum operating temperatureof thermocouple isolation 1446. Thermocouple isolation 1446 may be movedalong the length of low resistance section 1118 as thermocouple 1194 ismoved along the length of conductor 1112 by spool 1294. In otherembodiments, thermocouple isolation 1446 may be placed at wellhead 1162.

[1420] In a temperature monitor embodiment, a temperature within awellbore in a formation is measured using a fiber assembly. The fiberassembly may include optical fibers made from quartz or glass. The fiberassembly may have fibers surrounded by an outer shell. The fibers mayinclude fibers that transmit temperature measurement signals. A fiberthat may be used for temperature measurements can be obtained from SensaHighway (Houston, Tex.). The fiber assembly may be placed within awellbore in the formation. The wellbore may be a heater well, amonitoring well, or a production well. Use of the fibers may be limitedby a maximum temperature resistance of the outer shell, which may beabout 800° C. in some embodiments. A signal may be sent down a fiberdisposed within a wellbore. The signal may be a signal generated by alaser or other optical device. Thermal noise may be developed in thefiber from conditions within the wellbore. The amount of noise may berelated to a temperature within the wellbore. In general, the more noiseon the fiber, the higher the temperature within the wellbore. This maybe due to changes in the index of refraction of the fiber as thetemperature of the fiber changes. The relationship between noise andtemperature may be characterized for a certain fiber. This relationshipmay be used to determine a temperature of the fiber along the length ofthe fiber. The temperature of the fiber may represent a temperaturewithin the wellbore.

[1421] In some in situ conversion process embodiments, a temperaturewithin a wellbore in a formation may be measured using pressure waves. Apressure wave may include a sound wave. Examples of using sound waves tomeasure temperature are shown in U.S. Pat. Nos. 5,624,188 to West;5,437,506 to Gray; 5,349,859 to Kleppe; 4,848,924 to Nuspl et al.;4,762,425 to Shakkottai et al.; and 3,595,082 to Miller, Jr., which areincorporated by reference as if fully set forth herein. Pressure wavesmay be provided into the wellbore. The wellbore may be a heater well, aproduction well, a monitoring well, or a test well. A test well may be awell placed in a formation that is used primarily for measurement ofproperties of the formation. A plurality of discontinuities may beplaced within the wellbore. A predetermined spacing may exist betweeneach discontinuity. The plurality of discontinuities may be placedinside a conduit placed within a wellbore. For example, the plurality ofdiscontinuities may be placed within a conduit used as a portion of aconductor-in-conduit heater or a conduit used to provide fluid into awellbore. The plurality of discontinuities may also be placed on anexternal surface of a conduit in a wellbore. A discontinuity mayinclude, but may not be limited to, an alumina centralizer, a stub, anode, a notch, a weld, a collar, or any such point that may reflect apressure wave.

[1422]FIG. 112 depicts a schematic view of an embodiment for usingpressure waves to measure temperature within a wellbore. Conduit 556 maybe placed within wellbore 1336. Plurality of discontinuities 1448 may beplaced within conduit 556. The discontinuities may be separated bysubstantially constant separation distance 560. Distance 560 may be, insome embodiments, about 1 m, about 5 m, or about 15 m. A pressure wavemay be provided into conduit 556 from pressure wave source 1450.Pressure wave source 1450 may include, but is not limited to, an airgun, an explosive device (e.g., blank shotgun), a piezoelectric crystal,a magnetostrictive transducer, an electrical sparker, or a compressedair source. A compressed air source may be operated or controlled by asolenoid valve. The pressure wave may propagate through conduit 556. Insome embodiments, an acoustic wave may be propagated through the wall ofthe conduit.

[1423] A reflection (or signal) of the pressure wave within conduit 556may be measured using wave measuring device 1452. Wave measuring device1452 may be, for example, a piezoelectric crystal, a magnetostrictivetransducer, or any device that measures a time-domain pressure of thewave within the conduit. Wave measuring device 1452 may determinetime-domain pressure wave 1454 that represents travel of the pressurewave within conduit 556. Each slight increase in pressure, or pressurespike 1456, represents a reflection of the pressure wave at adiscontinuity 1448. The pressure wave may be repeatedly provided intothe wellbore at a selected frequency. The reflected signal may becontinuously measured to increase a signal-to-noise ratio for pressurespike 1456 in the reflected signal. This may include using a repetitivestacking of signals to reduce noise. A repeatable pressure wave sourcemay be used. For example, repeatable signals may be producible from apiezoelectric crystal. A trigger signal may be used to start wavemeasuring device 1452 and pressure wave source 1450. The time, asmeasured using pressure wave 1454, may be used with the distance betweeneach discontinuity 1448 to determine an average temperature between thediscontinuities for a known gas within conduit 556. Since the velocityof the pressure wave varies with temperature within conduit 556, thetime for travel of the pressure wave between discontinuities will varywith an average temperature between the discontinuities. For dry airwithin a conduit or wellbore, the temperature may be approximated usingthe equation:

c=33,145×(1+T/273.16)^(1/2);  (42)

[1424] in which c is the velocity of the wave in cm/sec and T is thetemperature in degrees Celsius. If the gas includes other gases or amixture of gases, EQN. 42 can be modified to incorporate properties ofthe alternate gas or the gas mixture. EQN. 42 can be derived from themore general equation for the velocity of a wave in a gas:

c=[(RT/M)(1+R/C _(v))]^(1/2);  (43)

[1425] in which R is the ideal gas constant, T is the temperature inKelvin, and C_(v) is the heat capacity of the gas.

[1426] Alternatively, a reference time-domain pressure wave can bedetermined at a known ambient temperature. Thus, a time-domain pressurewave determined at an increased temperature within the wellbore may becompared to the reference pressure wave to determine an averagetemperature within the wellbore after heating the formation. The changein velocity between the reference pressure wave and the increasedtemperature pressure wave, as measured by the change in distance betweenpressure spikes 1456, can be used to determine the increased temperaturewithin the conduit. Use of pressure waves to measure an averagetemperature may require relatively low maintenance. Using the velocityof pressure waves to measure temperature may be less expensive thanother temperature measurement methods.

[1427] In some embodiments, a heat source may be turned down and/or offafter an average temperature in a formation reaches a selectedtemperature. Turning down and/or off the heat source may reduce inputenergy costs, inhibit overheating of the formation, and allow heat totransfer into colder regions of the formation.

[1428] In some in situ conversion process embodiments, electrical powerused in heating a hydrocarbon containing formation may be supplied fromalternate energy sources. Alternate energy sources include, but are notlimited to, solar power, wind power, hydroelectric power, geothermalpower, biomass sources (i.e., agricultural and forestry by-products andenergy crops), and tidal power. Electric heaters used to heat aformation may use any available current, voltage (AC or DC), orfrequency that will not result in damage to the heater element. Becausethe heaters can be operated at a wide variety of voltages orfrequencies, transformers or other conversion equipment may not beneeded to allow for the use of electricity from alternate energy sourcesto power the electric heaters. This may significantly reduce equipmentcosts associated with using alternate energy sources, such as wind powerin which a significant cost is associated with equipment thatestablishes a relatively narrow current and/or voltage range.

[1429] Power generated from alternate energy sources may be generated ator proximate an area for treating a hydrocarbon containing formation.For example, one or more solar panels and equipment for converting solarenergy to electricity may be placed at a location proximate a formation.A wind farm, which includes a plurality of wind turbines, may be placednear a formation that is to be, or is being, subjected to an in situconversion process. A power station that combusts or otherwise useslocal or imported biomass for electrical generation may be placed near aformation that is to be, or is being, subjected to an in situ conversionprocess. If suitable geothermal or hydroelectric sites are locatedsufficiently nearby, these resources may be used for power generation.Power for electric heaters may be generated at or proximate the locationof a formation, thus reducing costs associated with obtaining and/ortransporting electrical power. In certain embodiments, steam and/orother exhaust fluids from treating a formation may be used to power agenerator that is also primarily powered by wind turbines.

[1430] In an embodiment in which an alternate energy source such as windor solar power is used to power electric heaters, supplemental power maybe needed to complement the alternate energy source when the alternateenergy source does not provide sufficient power to supply the heaters.For example, with a wind power source, during times when there isinsufficient wind to power a wind turbine to provide power to anelectric heater, the additional power required may be obtained from linepower sources such as a fossil fuel plant or nuclear power plant. Inother embodiments, power from alternate energy sources may be used forsupplemental power in addition to power from line power sources toreduce costs associated with heating a formation.

[1431] Alternate energy sources such as wind or solar power may be usedto supplement or replace electrical grid power during peak energy costtimes. If excess electricity that is compatible with the electricitygrid is generated using alternate energy sources, the excess electricitymay be sold to the grid. If excess electricity is generated, and if theexcess energy is not easily compatible with an existing electricitygrid, the excess electricity may be used to create stored energy thatcan be recaptured at a later time. Methods of energy storage mayinclude, but are not limited to, converting water to oxygen andhydrogen, powering a flywheel for later recovery of the mechanicalenergy, pumping water into a higher reservoir for later use as ahydroelectric power source, and/or compression of air (as in undergroundcaverns or spent areas of the reservoir).

[1432] Use of wind, solar, hydroelectric, biomass, or other such energysources in an in situ conversion process essentially converts thealternate energy into liquid transportation fuels and other energycontaining hydrocarbons with a very high efficiency. Alternate energysource usage may allow reduced life cycle greenhouse gas emissions, asin many cases the alternate energy sources (other than biomass) wouldreplace an equivalent amount of power generated by fossil fuel. Even inthe case of biomass, the carbon dioxide emitted would not come fromfossil fuel, but would instead be recycled from the existing globalcarbon portfolio through photosynthesis. Unlike with fossil fuelcombustion, there would therefore be no net addition of carbon dioxideto the atmosphere. If carbon dioxide from the biomass was captured andsequestered underground or elsewhere, there may be a net removal ofcarbon from the environment.

[1433] Use of alternate energy sources may allow for formation heatingin areas where a power grid is lacking or where there otherwise isinsufficient coal, oil, or natural gas available for power generation.In embodiments of in situ conversion processes that use combustion(e.g., natural distributed combustors) for heating a portion of aformation, the use of alternate energy sources may allow start upwithout the need for construction of expensive power plants or gridconnections.

[1434] The use of alternate energy sources is not limited to supplyingelectricity for electric heaters. Alternate energy sources may also beused to supply power to treatment facilities for processing fluidsproduced from a formation. Alternate energy sources may supply fuel forsurface burners or other gas combustors. For example, biomass mayproduce methane and/or other combustible hydrocarbons for reservoirheating.

[1435]FIG. 113 illustrates a schematic of an embodiment using wind togenerate electricity to heat a formation. Wind farm 1458 may include oneor more windmills. The windmills may be of any type of mechanism thatconverts wind to a usable mechanical form of motion. For example,windmill 1460 can be a design as shown in the embodiment of FIG. 113 orhave a design shown as an example in FIG. 114. In some embodiments, thewind farm may include advanced windmills as suggested by the NationalRenewable Energy Laboratory (Golden, Colo.). Wind farm 1458 may providepower to generator 1462. Generator 1462 may convert power from wind farm1458 into electrical power. In some embodiments, each windmill mayinclude a generator. Electrical power from generator 1462 may besupplied to formation 678. The electrical power may be used in formation678 to power heaters, pumps, or any electrical equipment that may beused in treating formation 678.

[1436]FIG. 115 illustrates a schematic of an embodiment for using solarpower to heat a formation. A heating fluid may be provided from storagetank 1464 to solar array 1466. The heating fluid may include any fluidthat has a relatively low viscosity with relatively good heat transferproperties (e.g., water, superheated steam, or molten ionic salts suchas molten carbonate). In certain embodiments, a low melting point ionicsalt may be used. Pump 1468 may be used to draw heating fluid fromstorage tank 1464 and provide the heating fluid to solar array 1466.Solar array 1466 may include any array designed to heat the heatingfluid to a relatively high temperature (e.g., above about 650° C.) usingsolar energy. For example, solar array 1466 may include a reflectivetrough with the heating fluid flowing through tubes within thereflective trough. The heating fluid may be provided to heater wells 520through hot fluid conduit 1470. Each heater well 520 may be coupled to abranch of hot fluid conduit 1470. A portion of the heating fluid may beprovided into each heater well 520.

[1437] Each heater well 520 may include two concentric conduits. Heatingfluid may be provided into a heater well through an inner conduit.Heating fluid may then be removed from the heater well through an outerconduit. Heat may be transferred from the heating fluid to at least aportion of the formation within each heater well 520 to provide heat tothe formation. A portion of each heater well 520 in an overburden of theformation may be insulated such that no heat is transferred from theheating fluid to the overburden. Heating fluid from each heater well 520may flow into cold fluid conduit 1472, which may return the heatingfluid to storage tank 1464. Heating fluid may have cooled within theheater well to a temperature of about 480° C. Heating fluid may berecirculated in a closed loop process as needed. An advantage of usingthe heating fluid to provide heat to the formation may be that solarpower is used directly to heat the formation without converting thesolar power to electricity.

[1438] Certain in situ conversion embodiments may include providing heatto a first portion of a hydrocarbon containing formation from one ormore heat sources. Formation fluids may be produced from the firstportion. A second portion of the formation may remain unpyrolyzed bymaintaining temperature in the second portion below a pyrolysistemperature of hydrocarbons in the formation. In some embodiments, thesecond portion or significant sections of the second portion may remainunheated.

[1439] A second portion that remains unpyrolyzed may be adjacent to afirst portion of the formation that is subjected to pyrolysis. Thesecond portion may provide structural strength to the formation. Thesecond portion may be between the first portion and the third portion.Formation fluids may be produced from the third portion of theformation. A processed formation may have a pattern that resembles astriped or checkerboard pattern with alternating pyrolyzed portions andunpyrolyzed portions. In some in situ conversion embodiments, columns ofunpyrolyzed portions of formation may remain in a formation that hasundergone in situ conversion.

[1440] Unpyrolyzed portions of formation among pyrolyzed portions offormation may provide structural strength to the formation. Thestructural strength may inhibit subsidence of the formation. Inhibitingsubsidence may reduce or eliminate subsidence problems such as changingsurface levels and/or decreasing permeability and flow of fluids in theformation due to compaction of the formation.

[1441] Temperature (and average temperatures) within a heatedhydrocarbon containing formation may vary depending on a number offactors. The factors may include, but are not limited to proximity to aheat source, thermal conductivity and thermal diffusivity of theformation, type of reaction occurring, type of hydrocarbon containingformation, and the presence of water within the hydrocarbon containingformation. A temperature within the hydrocarbon containing formation maybe assessed using a numerical simulation model. The numerical simulationmodel may calculate a subsurface temperature distribution. In addition,the numerical simulation model may assess various properties of asubsurface formation using the calculated temperature distribution.

[1442] Assessed properties of the subsurface formation may include, butare not limited to, thermal conductivity of the subsurface portion ofthe formation and permeability of the subsurface portion of theformation. The numerical simulation model may also assess variousproperties of fluid formed within a subsurface formation using thecalculated temperature distribution. Assessed properties of formed fluidmay include, but are not limited to, a cumulative volume of a fluidformed in the formation, fluid viscosity, fluid density, and acomposition of the fluid in the formation. The numerical simulationmodel may be used to assess the performance of commercial-scaleoperation of a small-scale field experiment. For example, a performanceof a commercial-scale development may be assessed based on, but is notlimited to, a total volume of product producible from a commercial-scaleoperation, amount of producible undesired products, and/or a time frameneeded before production becomes economical.

[1443] In some in situ conversion process embodiments, the in situconversion process increases a temperature or average temperature withina selected portion of a hydrocarbon containing formation. A temperatureor average temperature increase (ΔT) in a specified volume (V) of thehydrocarbon containing formation may be assessed for a given heat inputrate (q) over time (t) by EQN. 44: $\begin{matrix}{{\Delta \quad T} = \frac{\sum\left( {q*t} \right)}{C_{V}*\rho_{B}*V}} & (44)\end{matrix}$

[1444] In EQN. 44, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the hydrocarboncontaining formation.

[1445] An in situ conversion process may include heating a specifiedvolume of hydrocarbon containing formation to a pyrolysis temperature oraverage pyrolysis temperature. Heat input rate (q) during a time (t)required to heat the specified volume (V) to a desired temperatureincrease (ΔT) may be determined or assessed using EQN. 45:

Σq*t=ΔT*C _(V)*ρ_(B) *V  (45)

[1446] In EQN. 45, an average heat capacity of the formation (C_(v)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the hydrocarboncontaining formation.

[1447] EQNS. 44 and 45 may be used to assess or estimate temperatures,average temperatures (e.g., over selected sections of the formation),heat input, etc. Such equations do not take into account other factors(such as heat losses), which would also have some effect on heating andtemperature assessments. However such factors can ordinarily beaddressed with correction factors.

[1448] In some in situ conversion process embodiments, a portion of ahydrocarbon containing formation may be heated at a heating rate in arange from about 0.1° C./day to about 50° C./day. Alternatively, aportion of a hydrocarbon containing formation may be heated at a heatingrate in a range of about 0.1° C./day to about 10° C./day. For example, amajority of hydrocarbons may be produced from a formation at a heatingrate within a range of about 0.1° C./day to about 10° C./day. Inaddition, a hydrocarbon containing formation may be heated at a rate ofless than about 0.7° C./day through a significant portion of a pyrolysistemperature range. The pyrolysis temperature range may include a rangeof temperatures as described in above embodiments. For example, theheated portion may be heated at such a rate for a time greater than 50%of the time needed to span the temperature range, more than 75% of thetime needed to span the temperature range, or more than 90% of the timeneeded to span the temperature range.

[1449] A rate at which a hydrocarbon containing formation is heated mayaffect the quantity and quality of the formation fluids produced fromthe hydrocarbon containing formation. For example, heating at highheating rates (e.g., as is done during a Fischer Assay analysis) mayallow for production of a large quantity of condensable hydrocarbonsfrom a hydrocarbon containing formation. The products of such a processmay be of a significantly lower quality than would be produced usingheating rates less than about 10° C./day. Heating at a rate oftemperature increase less than approximately 10° C./day may allowpyrolysis to occur within a pyrolysis temperature range in whichproduction of undesirable products and heavy hydrocarbons may bereduced. In addition, a rate of temperature increase of less than about3° C./day may further increase the quality of the produced condensablehydrocarbons by further reducing the production of undesirable productsand further reducing production of heavy hydrocarbons from a hydrocarboncontaining formation.

[1450] In some in situ conversion process embodiments, controllingtemperature within a hydrocarbon containing formation may involvecontrolling a heating rate within the formation. For example,controlling the heating rate such that the heating rate is less thanapproximately 3° C./day may provide better control of temperature withinthe hydrocarbon containing formation.

[1451] An in situ process for hydrocarbons may include monitoring a rateof temperature increase at a production well. A temperature within aportion of a hydrocarbon containing formation, however, may be measuredat various locations within the portion of the formation. An in situprocess may include monitoring a temperature of the portion at amidpoint between two adjacent heat sources. The temperature may bemonitored over time to allow for calculation of a rate of temperatureincrease. A rate of temperature increase may affect a composition offormation fluids produced from the formation. Energy input into aformation may be adjusted to change a heating rate of the formationbased on calculated rate of temperature increase in the formation topromote production of desired products.

[1452] In some embodiments, a power (Pwr) required to generate a heatingrate (h) in a selected volume (V) of a hydrocarbon containing formationmay be determined by EQN. 46:

Pwr=h*V*C _(V)*ρ_(B)  (46)

[1453] In EQN. 46, an average heat capacity of the hydrocarboncontaining formation is described as C_(V). The average heat capacity ofthe hydrocarbon containing formation may be a relatively constant value.Average heat capacity may be estimated or determined using one or moresamples taken from a hydrocarbon containing formation, or the averageheat capacity may be measured in situ using a thermal pulse test.Methods of determining average heat capacity based on a thermal pulsetest are described by I. Berchenko, E. Detournay, N. Chandler, J.Martino, and E. Kozak, “In-situ measurement of some thermoporoelasticparameters of a granite” in Poromechanics, A Tribute to Maurice A.Biot., pages 545-550, Rotterdam, 1998 (Balkema), which is incorporatedby reference as if fully set forth herein.

[1454] An average bulk density of the hydrocarbon containing formationis described as ρ_(B). The average bulk density of the hydrocarboncontaining formation may be a relatively constant value. Average bulkdensity may be estimated or determined using one or more samples takenfrom a hydrocarbon containing formation. In certain embodiments, theproduct of average heat capacity and average bulk density of thehydrocarbon containing formation may be a relatively constant value(such product can be assessed in situ using a thermal pulse test).

[1455] A determined power may be used to determine heat provided from aheat source into the selected volume such that the selected volume maybe heated at a heating rate, h. For example, a heating rate may be lessthan about 3° C./day, and even less than about 2° C./day. A heating ratewithin a range of heating rates may be maintained within the selectedvolume. It is to be understood that in this context “power” is used todescribe energy input per time. The form of such energy input may vary(e.g., energy may be provided from electrical resistance heaters,combustion heaters, etc.).

[1456] The heating rate may be selected based on a number of factorsincluding, but not limited to, the maximum temperature possible at thewell, a predetermined quality of formation fluids that may be producedfrom the formation, and/or spacing between heat sources. A quality ofhydrocarbon fluids may be defined by an API gravity of condensablehydrocarbons, by olefin content, by the nitrogen, sulfur and/or oxygencontent, etc. In an in situ conversion process embodiment, heat may beprovided to at least a portion of a hydrocarbon containing formation toproduce formation fluids having an API gravity of greater than about20°. The API gravity may vary, however, depending on a number of factorsincluding the heating rate and a pressure within the portion of theformation and the time relative to initiation of the heat sources whenthe formation fluid is produced.

[1457] Subsurface pressure in a hydrocarbon containing formation maycorrespond to the fluid pressure generated within the formation. Heatinghydrocarbons within a hydrocarbon containing formation may generatefluids by pyrolysis. The generated fluids may be vaporized within theformation. Vaporization and pyrolysis reactions may increase thepressure within the formation. Fluids that contribute to the increase inpressure may include, but are not limited to, fluids produced duringpyrolysis and water vaporized during heating. As temperatures within aselected section of a heated portion of the formation increase, apressure within the selected section may increase as a result ofincreased fluid generation and vaporization of water. Controlling a rateof fluid removal from the formation may allow for control of pressure inthe formation.

[1458] In some embodiments, pressure within a selected section of aheated portion of a hydrocarbon containing formation may vary dependingon factors such as depth, distance from a heat source, a richness of thehydrocarbons within the hydrocarbon containing formation, and/or adistance from a producer well. Pressure within a formation may bedetermined at a number of different locations (e.g., near or atproduction wells, near or at heat sources, or at monitor wells).

[1459] Heating of a hydrocarbon containing formation to a pyrolysistemperature range may occur before substantial permeability has beengenerated within the hydrocarbon containing formation. An initial lackof permeability may inhibit the transport of generated fluids from apyrolysis zone within the formation to a production well. As heat isinitially transferred from a heat source to a hydrocarbon containingformation, a fluid pressure within the hydrocarbon containing formationmay increase proximate a heat source. Such an increase in fluid pressuremay be caused by generation of fluids during pyrolysis of at least somehydrocarbons in the formation. The increased fluid pressure may bereleased, monitored, altered, and/or controlled through the heat source.For example, the heat source may include a valve that allows for removalof some fluid from the formation. In some heat source embodiments, theheat source may include an open wellbore configuration that inhibitspressure damage to the heat source.

[1460] In some in situ conversion process embodiments, pressuregenerated by expansion of pyrolysis fluids or other fluids generated inthe formation may be allowed to increase although an open path to theproduction well or any other pressure sink may not yet exist in theformation. The fluid pressure may be allowed to increase towards alithostatic pressure. Fractures in the hydrocarbon containing formationmay form when the fluid approaches the lithostatic pressure. Forexample, fractures may form from a heat source to a production well. Thegeneration of fractures within the heated portion may relieve some ofthe pressure within the portion.

[1461] When permeability or flow channels to production wells areestablished, pressure within the formation may be controlled bycontrolling production rate from the production wells. In someembodiments, a back pressure may be maintained at production wells or atselected production wells to maintain a selected pressure within theheated portion.

[1462] A formation (e.g., an oil shale formation) may include one ormore lean zones. Lean zones may include zones with a relatively lowkerogen content (e.g., less than about 0.06 L/kg in oil shale). Richzones may include zones with a relatively high kerogen content (e.g.,greater than about 0.06 L/kg in oil shale). Lean zones may exist at anupper or lower boundary of a rich zone and/or may exist as lean zonelayers between layers of rich zone layers. Generally, lean zones may bemore permeable and include more brittle material than rich zones. Inaddition, rich zones typically have a lower thermal conductivity thanlean zones. For example, lean zones may include zones through whichfluids (e.g., water) can flow. In some cases, however, lean zones mayhave lower permeabilities and/or include somewhat less brittle material.In an in situ process for treating a formation, heat may be applied torich zones with substantial amounts of hydrocarbons to pyrolyze andproduce hydrocarbons from the rich zones. Applying heat to lean zonesmay be inhibited to avoid creating fractures within the lean zones(e.g., when the lean zone is at an outer boundary of the formation).

[1463] In certain embodiments, heat may be applied to a lean zone (e.g.,a lean zone between two rich zones) to create and propagate fractureswithin the lean zone. Applying heat to a lean zone and creatingfractures within the lean zone may allow for earlier production ofhydrocarbons from a formation. In some embodiments, heating of the leanzone may not be needed as fractures or high permeability is initiallypresent within the lean zone. Formation fluids may flow through apermeable lean zone more rapidly than through other portions of aformation. Formation fluids may be produced through a production wellearlier during heating of the formation in the presence of a permeablelean zone. The permeable lean zone may provide a pathway for the flow offluids between the heat front where fluids are pyrolyzed and theproduction well. Production of formation fluids through the permeablelean zone may increase the production of fluids as liquids, inhibitpressure buildup in the formation, inhibit failure/collapse of wells dueto high pressures, and/or allow for convective heat transfer through thefractures.

[1464]FIG. 116 depicts a cross-sectional representation of an embodimentfor treating lean zones 1474 and rich zones 1476 of a formation. Leanzones 1474 and rich zones 1476 are below overburden 524. In someembodiments, lean zones 1474 may be relatively permeable sections of theformation. For example, lean zones 1474 may have an average permeabilitythickness product of greater than about 100 millidarcy feet. In certainembodiments, lean zones 1474 may have an average permeability thicknessproduct of greater than about 1000 millidarcy feet or greater than about5000 millidarcy feet. Rich zones 1476 may be sections of the formationthat are selected for treatment based on a richness of the section. Richzones 1476 may have an initial average permeability thickness product ofless than about 10 millidarcy feet. Certain rich zones may have aninitial average permeability thickness product of less than about 1millidarcy feet or less than about 0.5 millidarcy feet.

[1465] Heat source 508 may be placed through overburden 524 and intoopening 544. Reinforcing material 1122 (e.g., cement) may seal a portionof opening 544 to overburden 524. Heat source 508 may apply heat to leanzones 1474 and/or rich zones 1476. In some embodiments, heat source 508may include a conductor with a thickness that is adjusted to providemore heat to rich zones 1476 than lean zones 1474 (i.e., the thicknessof the conductor is larger proximate the lean zones than the thicknessof the conductor proximate the rich zones).

[1466] In certain embodiments, rich zones 1476 may not fracture. Forexample, the rich zones may have a ductility that is high enough toinhibit the formation of fractures. A formation (e.g., an oil shaleformation) may have one or more lean zones 1474 and one or more richzones 1476 that are layered throughout the formation as shown in FIG.116. Formation fluids formed in rich zones 1476 may be produced throughpre-existing fractures in lean zone 1474. In some embodiments, lean zone1474 may have a permeability sufficiently high to allow production offluids. This high permeability may be initially present in the lean zonebecause of, for example, water flow through the lean zone that leachedout minerals over geological time prior to initiation of the in situconversion process. In some embodiments, the application of heat to theformation from heat sources may produce, or increase the size of,fractures 1478 and/or increase the permeability in lean zones 1474.Fractures 1478 may increase the permeability of lean zones 1474 byproviding a pathway for fluids to propagate through the lean zones.

[1467] During early times of heating, permeability may be created nearopening 544. Permeability may be created in permeable zone 1480 adjacentopening 544. Permeable zone 1480 will increase in size and move outradially as the heat front produced by heat source 508 moves outward. Asthe heat front migrates through the formation, hydrocarbons may bepyrolyzed as temperatures within rich zones 1476 reach pyrolysistemperatures. Pyrolyzation of the hydrocarbons, along with heating ofthe rich zones, may increase the permeability of rich zones 1476. Atlater times of heating, hydrocarbons in coking portion 1482 of permeablezone 1480 may coke as temperatures within this portion increase tocoking temperatures. At some point permeable zone 1480 will move outwardto a distance from opening 544 at which no coking of hydrocarbons occurs(i.e., a distance at which temperatures do not approach cokingtemperatures). Permeable zone 1480 may continue to expand with themigration of the heat front through the formation. If sufficient wateris present, coking may be suppressed near opening 544.

[1468] In certain embodiments, fluids formed in rich zones 1476 may flowinto lean zones 1474 through permeable zone 1480. Coking portion 1482may inhibit the flow of fluids between rich zones 1476 and lean zones1474. Fluids may continue to flow into lean zones 1474 through un-cokedportions of permeable zone 1480. In some embodiments, fluids may flow toopening 544 (e.g., during early times of heating before permeable zone1480 has sufficient permeability for fluid flow into the lean zones).Fluids that flow to opening 544 may be produced through the opening orbe allowed to flow through lean zones 1474 to production well 512. Inaddition, during early times of heating, some coke formation may occurnear opening 544.

[1469] Allowing formation fluids to be produced through lean zones 1474may allow for earlier production of fluids formed in rich zones 1476.For example, fluids formed in rich zones 1474 may be produced throughlean zones 1474 before sufficient permeability has been created in therich zones for fluids to flow directly within the rich zones toproduction well 512. Producing at least some fluids through lean zone1474 or through opening 544 may inhibit a buildup of pressure within theformation during heating of the formation.

[1470] In certain embodiments, fractures 1478 may propagate in ahorizontal direction. However, fractures 1478 may. propagate in otherdirections depending on, for example, a depth of the fracturing layerand structure of the fracturing layer. As an example, oil shaleformations in the Piceance basin in Colorado that are deeper than about125 m below the surface tend to have fractures that propagate at anangle or vertically. In certain embodiments, the creation of angled orvertical fractures may be inhibited to inhibit fracturing into anaquifer or other environmentally sensitive area.

[1471] In some embodiments, applying heat to rich zones 1476 may createfractures within the rich zones. Fractures within rich zone 1476 may beless likely to initially occur due to the more ductile (less brittle)composition of the rich zone as compared to lean zones 1474. In anembodiment, fractures may develop that connect lean zones 1474 and richzones 1476. These fractures may provide a path for propagation of fluidsfrom one zone to the other zone.

[1472] Production well 512 may be placed at an angle, vertically, orhorizontally into lean zones 1474 and rich zones 1476. Production well512 may produce formation fluids from lean zones 1474 and/or rich zones1476.

[1473] In some embodiments, more than one production well may be placedin lean zones 1474 and/or rich zones 1476. A number of production wellsmay be determined by, for example, a desired product quality of theproduced fluids, a desired production rate, a desired weight percentageof a component in the produced fluids, etc.

[1474] In other embodiments, formation fluids may be produced throughopening 544, which may be uncased or perforated. Producing formationfluids through opening 544 tends to increase cracking of hydrocarbons(from the heat provided by heat source 508) as the fluids propagatealong the length of the opening. Fluids produced through opening 544 mayhave lower carbon numbers than fluids produced through production well512.

[1475] In an in situ conversion process embodiment, pressure may beincreased within a selected section of a portion of a hydrocarboncontaining formation to a selected pressure during pyrolysis. A selectedpressure may be within a range from about 2 bars absolute to about 72bars absolute or, in some embodiments, 2 bars absolute to 36 barsabsolute. Alternatively, a selected pressure may be within a range fromabout 2 bars absolute to about 18 bars absolute. In some in situconversion process embodiments, a majority of hydrocarbon fluids may beproduced from a formation having a pressure within a range from about 2bars absolute to about 18 bars absolute. The pressure during pyrolysismay vary or be varied. The pressure may be varied to alter and/orcontrol a composition of a formation fluid produced, to control apercentage of condensable fluid as compared to non-condensable fluid,and/or to control an API gravity of fluid being produced. For example,decreasing pressure may result in production of a larger condensablefluid component. The condensable fluid component may contain a largerpercentage of olefins.

[1476] In some in situ conversion process embodiments, increasedpressure due to fluid generation may be maintained within the heatedportion of the formation. Maintaining increased pressure within aformation may inhibit formation subsidence during in situ conversion.Increased formation pressure may promote generation of high qualityproducts during pyrolysis. Increased formation pressure may facilitatevapor phase production of fluids from the formation. Vapor phaseproduction may allow for a reduction in size of collection conduits usedto transport fluids produced from the formation. Increased formationpressure may reduce or eliminate the need to compress formation fluidsat the surface to transport the fluids in collection conduits totreatment facilities. Maintaining increased pressure within a formationmay also facilitate generation of electricity from producednon-condensable fluid. For example, the produced non-condensable fluidmay be passed through a turbine to generate electricity.

[1477] Increased pressure in the formation may also be maintained toproduce more and/or improved formation fluids. In certain in situconversion process embodiments, significant amounts (e.g., a majority)of the hydrocarbon fluids produced from a formation may benon-condensable hydrocarbons. Pressure may be selectively increasedand/or maintained within the formation to promote formation of smallerchain hydrocarbons in the formation. Producing small chain hydrocarbonsin the formation may allow more non-condensable hydrocarbons to beproduced from the formation. The condensable hydrocarbons produced fromthe formation at higher pressure may be of a higher quality (e.g.,higher API gravity) than condensable hydrocarbons produced from theformation at a lower pressure.

[1478] A high pressure may be maintained within a heated portion of ahydrocarbon containing formation to inhibit production of formationfluids having carbon numbers greater than, for example, about 25. Somehigh carbon number compounds may be entrained in vapor in the formationand may be removed from the formation with the vapor. A high pressure inthe formation may inhibit entrainment of high carbon number compoundsand/or multi-ring hydrocarbon compounds in the vapor. Increasingpressure within the hydrocarbon containing formation may increase aboiling point of a fluid within the portion. High carbon numbercompounds and/or multi-ring hydrocarbon compounds may remain in a liquidphase in the formation for significant time periods. The significanttime periods may provide sufficient time for the compounds to pyrolyzeto form lower carbon number compounds.

[1479] Maintaining increased pressure within a heated portion of theformation may surprisingly allow for production of large quantities ofhydrocarbons of increased quality. Maintaining increased pressure maypromote vapor phase transport of pyrolyzation fluids within theformation. Increasing the pressure often permits production of lowermolecular weight hydrocarbons since such lower molecular weighthydrocarbons will more readily transport in the vapor phase in theformation.

[1480] Generation of lower molecular weight hydrocarbons (andcorresponding increased vapor phase transport) is believed to be due, inpart, to autogenous generation and reaction of hydrogen within a portionof the hydrocarbon containing formation. For example, maintaining anincreased pressure may force hydrogen generated during pyrolysis into aliquid phase (e.g., by dissolving). Heating the portion to a temperaturewithin a pyrolysis temperature range may pyrolyze hydrocarbons withinthe formation to generate pyrolyzation fluids in a liquid phase. Thegenerated components may include double bonds and/or radicals. H₂ in theliquid phase may reduce double bonds of the generated pyrolyzationfluids, thereby reducing a potential for polymerization or formation oflong chain compounds from the generated pyrolyzation fluids. Inaddition, hydrogen may also neutralize radicals in the generatedpyrolyzation fluids. Therefore, H₂ in the liquid phase may inhibit thegenerated pyrolyzation fluids from reacting with each other and/or withother compounds in the formation. Shorter chain hydrocarbons may enterthe vapor phase and may be produced from the formation.

[1481] Increasing the formation pressure may reduce the potential forcoking within a selected section of the formation. Coking reactions mayoccur substantially in a liquid phase at high temperatures. Cokingreactions may occur in localized sections of the formation. An in situconversion process embodiment may slowly raise temperature within aselected section. Pyrolysis reactions that occur in a liquid phase mayresult in the production of small molecules in the liquid phase. Thesmall molecules may leave the liquid as a vapor due to local temperatureand pressure conditions. The small molecules undergoing phase changefrom a liquid phase to a vapor phase may absorb a significant amount ofheat. The absorbed heat may help to inhibit high temperatures that couldresult in coking reactions. In addition, increased pressure in theformation may result in a significant amount of hydrogen being forcedinto the liquid phase present in the formation. The hydrogen may inhibitpolymerization reactions that result in the generation of largehydrocarbon molecules. Inhibiting the production of large hydrocarbonmolecules may result in less coking within the formation.

[1482] Operating an in situ conversion process at increased pressure mayallow for vapor phase production of formation fluid from the formation.Vapor phase production may permit increased recovery of lighter (andrelatively high quality) pyrolyzation fluids. Vapor phase production mayresult in less formation fluid being left in the formation after thefluid is produced by pyrolysis. Vapor phase production may allow forfewer production wells in the formation than are present using liquidphase or liquid/vapor phase production. Fewer production wells maysignificantly reduce equipment costs associated with an in situconversion process.

[1483] In an embodiment, a portion of a hydrocarbon containing formationmay be heated to increase a partial pressure of H₂. In some embodiments,an increased H₂ partial pressure may include H₂ partial pressures in arange from about 0.5 bars absolute to about 7 bars absolute.Alternatively, an increased H₂ partial pressure range may include H₂partial pressures in a range from about 5 bars absolute to about 7 barsabsolute. For example, a majority of hydrocarbon fluids may be producedwherein a H₂ partial pressure is within a range of about 5 bars absoluteto about 7 bars absolute. A range of H₂ partial pressures within thepyrolysis H₂ partial pressure range may vary depending on, for example,temperature and pressure of the heated portion of the formation.

[1484] Maintaining a H₂ partial pressure within the formation of greaterthan atmospheric pressure may increase an API value of producedcondensable hydrocarbon fluids. Maintaining an increased H₂ partialpressure may increase an API value of produced condensable hydrocarbonfluids to greater than about 25° or, in some instances, greater thanabout 30°. Maintaining an increased H₂ partial pressure within a heatedportion of a hydrocarbon containing formation may increase aconcentration of H₂ within the heated portion. The H₂ may be availableto react with pyrolyzed components of the hydrocarbons. Reaction of H₂with the pyrolyzed components of hydrocarbons may reduce polymerizationof olefins into tars and other cross-linked, difficult to upgrade,products. Therefore, production of hydrocarbon fluids having low APIgravity values may be inhibited.

[1485] In an embodiment, a method for treating a hydrocarbon containingformation in situ may include adding hydrogen to a selected section ofthe formation when the selected section is at or undergoing certainconditions. For example, the hydrogen may be added through a heater wellor production well located in or proximate the selected section. Sincehydrogen is sometimes in relatively short supply (or relativelyexpensive to make or procure), hydrogen may be added when conditions inthe formation optimize the use of the added hydrogen. For example,hydrogen produced in a section of a formation undergoing synthesis gasgeneration may be added to a section of the formation undergoingpyrolysis. The added hydrogen in the pyrolysis section of the formationmay promote formation of aliphatic compounds and inhibit formation ofolefinic compounds that reduce the quality of hydrocarbon fluidsproduced from formation.

[1486] In some embodiments, hydrogen may be added to the selectedsection after an average temperature of the formation is at a pyrolysistemperature (e.g., when the selected section is at least about 270° C.).In some embodiments, hydrogen may be added to the selected section afterthe average temperature is at least about 290° C., 320° C., 375° C., or400° C. Hydrogen may be added to the selected section before an averagetemperature of the formation is about 400° C. In some embodiments,hydrogen may be added to the selected section before the averagetemperature is about 300° C. or about 325° C.

[1487] The average temperature of the formation may be controlled byselectively adding hydrogen to the selected section of the formation.Hydrogen added to the formation may react in exothermic reactions. Theexothermic reactions may heat the formation and reduce the amount ofenergy that needs to be supplied from heat sources to the formation. Insome embodiments, an amount of hydrogen may be added to the selectedsection of the formation such that an average temperature of theformation does not exceed about 400° C.

[1488] A valve may maintain, alter, and/or control a pressure within aheated portion of a hydrocarbon containing formation. For example, aheat source disposed within a hydrocarbon containing formation may becoupled to a valve. The valve may release fluid from the formationthrough the heat source. In addition, a pressure valve may be coupled toa production well within the hydrocarbon containing formation. In someembodiments, fluids released by the valves may be collected andtransported to a surface unit for further processing and/or treatment.

[1489] An in situ conversion process for hydrocarbons may includeproviding heat to a portion of a hydrocarbon containing formation andcontrolling a temperature, rate of temperature increase, and/or pressurewithin the heated portion. A temperature and/or a rate of temperatureincrease of the heated portion may be controlled by altering the energysupplied to heat sources in the formation.

[1490] Controlling pressure and temperature within a hydrocarboncontaining formation may allow properties of the produced formationfluids to be controlled. For example, composition and quality offormation fluids produced from the formation may be altered by alteringan average pressure and/or an average temperature in a selected sectionof a heated portion of the formation. The quality of the produced fluidsmay be evaluated based on characteristics of the fluid such as, but notlimited to, API gravity, percent olefins in the produced formationfluids, ethene to ethane ratio, atomic hydrogen to carbon ratio, percentof hydrocarbons within produced formation fluids having carbon numbersgreater than 25, total equivalent production (gas and liquid), totalliquids production, and/or liquid yield as a percent of Fischer Assay.Controlling the quality of the produced formation fluids may includecontrolling average pressure and average temperature in the selectedsection such that the average assessed pressure in the selected sectionis greater than the pressure (p) as set forth in the form of EQN. 47 foran assessed average temperature (T) in the selected section:$\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (47)\end{matrix}$

[1491] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the selected property.

[1492] EQN. 47 may be rewritten such that the natural log of pressure isa linear function of the inverse of temperature. This form of EQN. 47 isexpressed as: ln(p)=A/T+B. In a plot of the natural log of absolutepressure as a function of the reciprocal of the absolute temperature, Ais the slope and B is the intercept. The intercept B is defined to bethe natural logarithm of the pressure as the reciprocal of thetemperature approaches zero. The slope and intercept values (A and B) ofthe pressure-temperature relationship may be determined from at leasttwo pressure-temperature data points for a given value of a selectedproperty. The pressure-temperature data points may include an averagepressure within a formation and an average temperature within theformation at which the particular value of the property was, or may be,produced from the formation. The pressure-temperature data points may beobtained from an experiment such as a laboratory experiment or a fieldexperiment.

[1493] A relationship between the slope parameter, A, and a value of aproperty of formation fluids may be determined. For example, values of Amay be plotted as a function of values of a formation fluid property. Acubic polynomial may be fitted to these data. For example, a cubicpolynomial relationship such as EQN. 48:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄;  (48)

[1494] may be fitted to the data, where a₁, a₂, a₃, and a₄ are empiricalconstants that describe a relationship between the first parameter, A,and a property of a formation fluid. Alternatively, relationships havingother functional forms such as another order polynomial, trigonometricfunction, or a logarithmic function may be fitted to the data. Valuesfor a₁, a₂, . . . , may be estimated from the results of the datafitting. Similarly, a relationship between the second parameter, B, anda value of a property of formation fluids may be determined. Forexample, values of B may be plotted as a function of values of aproperty of a formation fluid. A cubic polynomial may also be fitted tothe data. For example, a cubic polynomial relationship such as EQN. 49:

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄;  (49)

[1495] may be fitted to the data, where b₁, b₂, b₃, and b₄ are empiricalconstants that may describe a relationship between the parameter B andthe value of a property of a formation fluid. As such, b₁, b₂, b₃, andb₄ may be estimated from results of fitting the data. TABLES 9 and 10list estimated empirical constants determined for several properties ofa formation fluid produced by an in situ conversion process from GreenRiver oil shale. TABLE 9 PROPERTY a₁ a₂ a₃ a₄ API Gravity −0.738549−8.893902 4752.182 −145484.6 Ethene/Ethane Ratio −15543409 3261335−303588.8 −2767.469 Weight Percent of Hydrocarbons 0.1621956 −8.85952547.9571 −24684.9 Having a Carbon Number Greater Than 25 Atomic H/CRatio 2950062 −16982456 32584767 −20846821 Liquid Production (gal/ton)119.2978 −5972.91 96989 −524689 Equivalent Liquid Production −6.24976212.9383 −777.217 −39353.47 (gal/ton) % Fischer Assay 0.5026013 −126.5929813.139 −252736

[1496] TABLE 10 PROPERTY b₁ b₂ b₃ b₄ API Gravity 0.003843 −0.2794243.391071 96.67251 Ethene/Ethane Ratio −8974.317 2593.058 −40.7887423.31395 Weight Percent of hydrocarbons −0.0005022 0.026258 −1.1269544.49521 Having a Carbon Number Greater Than 25 Atomic H/C Ratio790.0532 −4199.454 7328.572 −4156.599 Liquid Production (gal/ton)−0.17808 8.914098 −144.999 793.2477 Equivalent Liquid Production−0.03387 2.778804 −72.6457 650.7211 (gal/ton) % Fischer Assay −0.00079010.196296 −15.1369 395.3574

[1497] To determine an average pressure and an average temperature forproducing a formation fluid having a selected property, the value of theselected property and the empirical constants may be used to determinevalues for the first parameter A and the second parameter B, accordingto EQNS. 50 and 51:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (50)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄  (51)

[1498] TABLES 11-17 list estimated values for the parameter A andapproximate values for the parameter B, as determined for a selectedproperty of a formation fluid produced by an in situ conversion processfrom Green River oil shale. TABLE 11 API Gravity A B 20° −59906.983.46594 25° 43778.5 66.85148 30° −30864.5 50.67593 35° −21718.537.82131 40° −16894.7 31.16965 45° −16946.8 33.60297

[1499] TABLE 12 Ethene/Ethane Ratio A B 0.20 −57379 83.145 0.10 −1605627.652 0.05 −11736 21.986 0.01 −5492.8 14.234

[1500] TABLE 13 Weight Percent of Hydrocarbons Having a Carbon NumberGreater Than 25 A B 25% −14206 25.123 20% −15972 28.442 15% −1791231.804 10% −19929 35.349 5% −21956 38.849 1% −24146 43.394

[1501] TABLE 14 Atomic H/C Ratio A B 1.7 −38360 60.531 1.8 −12635 23.9891.9 −7953.1 17.889 2.0 −6613.1 16.364

[1502] TABLE 15 Liquid Production (gal/ton) A B 14 gal/ton −10179 21.78016 gal/ton −13285 25.866 18 gal/ton −18364 32.882 20 gal/ton −1968934.282

[1503] TABLE 16 Equivalent Liquid Production (gal/ton) A B 20 gal/ton−19721 38.338 25 gal/ton −23350 42.052 30 gal/ton −39768.9 57.68

[1504] TABLE 17 % Fischer Assay A B 60% −11118 23.156 70% −13726 26.63580% −20543 36.191 90% −28554 47.084

[1505] In some in situ conversion process embodiments, the determinedvalues for the parameter A and the parameter B may be used to determinean average pressure in the selected section of the formation using anassessed average temperature, T, in the selected section. For example,an average pressure of the selected section may be determined by EQN.52:

p=exp[(A/T)+B],  (52)

[1506] in which p is expressed in psia, and T is expressed in Kelvin.Alternatively, an average absolute pressure of the selected section,measured in bars, may be determined using EQN. 53:

p _(bars)=exp[(A/T)+B−2.6744].  (53)

[1507] An average pressure within the selected section may be controlledsuch that the average pressure within the selected section is about thevalue calculated from the equation. Formation fluid produced from theselected section may approximately have the chosen value of the selectedproperty, and therefore, the desired quality.

[1508] In some in situ conversion process embodiments, the determinedvalues for the parameter A and the parameter B may be used to determinean average temperature in the selected section of the formation using anassessed average pressure, p, in the selected section. Using therelationships described above, an average temperature within theselected section may be controlled to approximate the calculated averagetemperature to produce hydrocarbon fluids having a selected property andquality.

[1509] Formation fluid properties may vary depending on a location of aproduction well in the formation. For example, a location of aproduction well with respect to a location of a heat source in theformation may affect the composition of formation fluid produced fromthe formation. Distance between a production well and a heat source inthe formation may be varied to alter the composition of formation fluidproducible from the formation. Having a short distance between aproduction well and a heat source or heat sources may allow a hightemperature to be maintained at and adjacent to the production well.Having a high temperature at and adjacent to the production well mayallow a substantial portion of pyrolyzation fluids flowing to andthrough the production well to crack to non-condensable compounds. Insome in situ conversion process embodiments, location of productionwells relative to heat sources may be selected to allow for productionof formation fluid having a large non-condensable gas fraction. In somein situ conversion process embodiments, location of production wellsrelative to heat sources may be selected to increase a condensable gasfraction of the produced formation fluids. During operation of in situconversion process embodiments, energy input into heat sources adjacentto production wells may be controlled to allow for production of adesired ratio of non-condensable to condensable hydrocarbons.

[1510] A carbon number distribution of a produced formation fluid mayindicate a quality of the produced formation fluid. In general,condensable hydrocarbons with low carbon numbers are considered to bemore valuable than condensable hydrocarbons having higher carbonnumbers. Low carbon numbers may include, for example, carbon numbersless than about 25. High carbon numbers may include carbon numbersgreater than about 25. In an in situ conversion process embodiment, thein situ conversion process may include providing heat to a portion of aformation so that a majority of hydrocarbons produced from the formationhave carbon numbers of less than approximately 25.

[1511] An in situ conversion process may be operated so that carbonnumbers of the largest weight fraction of hydrocarbons produced from theformation are about 12, for a given time period. The time period may betotal time of operation, or a selected subset of operation (e.g., a day,week, month, year, etc.). Operating conditions of an in situ conversionprocess may be adjusted to shift the carbon number of the largest weightfraction of hydrocarbons produced from the formation. For example,increasing pressure in a formation may shift the carbon number of thelargest weight fraction of hydrocarbons produced from the formation to asmaller carbon number. Shifting the carbon number of the largest weightfraction of hydrocarbons produced from the formation may also beexpressed as shifting the mean carbon number of the carbon numberdistribution.

[1512] In some in situ conversion process embodiments, hydrocarbonsproduced from the formation may have a mean carbon number less thanabout 25. In some in situ conversion process embodiments, less thanabout 15 weight % of the hydrocarbons in the condensable hydrocarbonshave carbon numbers greater than approximately 25. In some embodiments,less than about 5 weight % of hydrocarbons in the condensablehydrocarbons have carbon numbers greater than about 25, and/or less thanabout 2 weight % of hydrocarbons in the condensable hydrocarbons havecarbon numbers greater than about 25.

[1513] In an in situ conversion process embodiment, the in situconversion process may include providing heat to at least a portion of ahydrocarbon containing formation at a rate sufficient to alter and/orcontrol production of olefins. The in situ conversion process mayinclude heating the portion at a rate to produce formation fluids havingan olefin content of less than about 10 weight % of condensablehydrocarbons of the formation fluids. Reducing olefin production mayreduce coating of pipe surfaces by the olefins, thereby reducingdifficulty associated with transporting hydrocarbons through the piping.Reducing olefin production may inhibit polymerization of hydrocarbonsduring pyrolysis, thereby increasing permeability in the formationand/or enhancing the quality of produced fluids (e.g., by lowering themean carbon number of the carbon number distribution for fluids producedfrom the formation, increasing API gravity, etc.).

[1514] In some in situ conversion process embodiments, however, theportion may be heated at a rate to allow for production of olefins fromformation fluid in sufficient quantities to allow for economic recoveryof the olefins. Olefins in produced formation fluid may be separatedfrom other hydrocarbons. Operating conditions (i.e., temperature andpressure) within the formation may be selected to control thecomposition of olefins produced along with other formation fluid. Forexample, operating conditions of an in situ conversion process may beselected to produce a carbon number distribution with a mean carbonnumber of about 9. Only a small weight fraction of the olefins producedmay have carbon numbers greater than 9. The small weight fraction maynot significantly affect the quality (e.g., API gravity) of the producedfluid from the formation. The fluid may remain easy to process even withenough olefins present to make separation of olefins economicallyviable.

[1515] In some in situ conversion process embodiments, a portion of theformation may be heated at a rate to selectively increase the content ofphenol and substituted phenols of condensable hydrocarbons in theproduced fluids. For example, phenol and/or substituted phenols may beseparated from condensable hydrocarbons. The separated compounds may beused to produce additional products. The resource may, in someembodiments, be selected to enhance production of phenol and/orsubstituted phenols.

[1516] Hydrocarbons in produced fluids may include a mixture of a numberof different hydrocarbon components. Hydrocarbons in formation fluidproduced from a formation may have a hydrogen to carbon atomic ratiothat is at least approximately 1.7 or above. For example, the hydrogento carbon atomic ratio of a produced fluid may be approximately 1.8,approximately 1.9, or greater. The ratio may be below two because of thepresence of aromatic compounds and/or olefins. Some of the hydrocarboncomponents are condensable and some are not. The fraction ofnon-condensable hydrocarbons within the produced fluid may be alteredand/or controlled by altering, controlling, and/or maintaining a hightemperature and/or high pressure during pyrolysis within the formation.Treatment facilities may separate hydrocarbon fluids fromnon-hydrocarbon fluids. Treatment facilities may also separatecondensable hydrocarbons from non-condensable hydrocarbons.

[1517] In some embodiments, the non-condensable hydrocarbons may includehydrocarbons having carbon numbers less than or equal to 5. Producedformation fluid may also include non-hydrocarbon, non-condensable fluidssuch as, but not limited to, H₂, CO₂, ammonia, H₂S, N₂ and/or CO. Incertain embodiments, non-condensable hydrocarbons of a fluid producedfrom a portion of a hydrocarbon containing formation may have a weightratio of hydrocarbons having carbon numbers from 2 through 4 (“C₂₋₄hydrocarbons”) to methane of greater than about 0.3, greater than about0.75, or greater than about 1 in some circumstances. Hydrocarbonresource characteristics may influence the ratio of C₂₋₄ hydrocarbons tomethane. For example, a ratio of C₂₋₄ hydrocarbons to methane for an oilshale or heavy hydrocarbon containing formation may be about 1, while aratio of C₂₋₄ hydrocarbons to methane for a coal formation processed atsimilar temperature and pressure conditions may be greater than about0.3. Operating conditions (e.g., temperature and pressure) may beadjusted to influence a ratio of C₂₋₄ hydrocarbons to methane. Forexample, producing hydrocarbons from a relatively hot formation at arelatively high pressure may produce significant amount of methane,which may result in a significantly lower value for the ratio of C₂₋₄hydrocarbons to methane as compared to fluid produced from the sameformation at milder temperature and pressure conditions.

[1518] An in situ conversion process may be able to produce a highweight ratio of C₂₋₄ hydrocarbons to methane as compared to ratiosproducible using other processes such as fire floods or steam floods.High weight ratios of C₂₋₄ hydrocarbons to methane may indicate thepresence of significant amounts of hydrocarbons with 2, 3, and/or 4carbons (e.g., ethane, ethene, propane, propene, butane, and butene).C₂₋₄ hydrocarbons may have significant value. The value of C₃ and C₄hydrocarbons may be many times (e.g., 2, 3, or greater) than the valueof methane. Production of hydrocarbon fluids having high C₂₋₄hydrocarbons to methane weight ratios may be due to conditions appliedto the formation during pyrolysis (e.g., controlled heating and/orpressure used in reducing environments or non-oxidizing environments).The conditions may allow for long chain hydrocarbons to be reduced tosmall (and in many cases more saturated) chain hydrocarbons with only aportion of the long chain hydrocarbons being reduced to methane orcarbon dioxide.

[1519] Methane and at least a portion of ethane may be separated fromnon-condensable hydrocarbons in produced fluid. The methane and ethanemay be utilized as natural gas. A portion of propane and butane may beseparated from non-condensable hydrocarbons of the produced fluid. Inaddition, the separated propane and butane may be utilized as fuels oras feedstocks for producing other hydrocarbons. Ethane, propane andbutane produced from the formation may be used to generate olefins. Aportion of the produced fluid having carbon numbers less than 4 may bereformed to produce additional H₂ and/or methane. In some in situconversion process embodiments, the reformation may be performed in theformation. In addition, ethane, propane, and butane may be separatedfrom the non-condensable hydrocarbons.

[1520] Formation fluid produced from a formation during a pyrolysisstage of an in situ conversion process may have a H₂ content of greaterthan about 5 weight %, greater than about 10 weight %, or even greaterthan about 15 weight %. The H₂ may be used for a variety of purposes.The purposes may include, but are not limited to, as a fuel for a fuelcell, to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenatehydrocarbon fluids ex situ.

[1521] Formation fluid produced from a formation may include somehydrogen sulfide. The hydrogen sulfide may be a non-condensable,non-hydrocarbon component of the formation fluid. The hydrogen sulfidemay be separated from other compounds. The separated hydrogen sulfidemay be used to produce, for example, sulfuric acid, fertilizer, and/orelemental sulfur.

[1522] Formation fluid produced from a formation during in situconversion may include carbon dioxide. Carbon dioxide produced from theformation may be used for a variety of purposes. The purposes mayinclude, but are not limited to, drive fluid for enhanced oil recovery,drive fluid for coal bed methane production, as a feedstock forproduction of urea, and/or a component of a synthesis gas fluidgenerating fluid. In some embodiments, a portion of carbon dioxideproduced during an in situ conversion process may be sequestered in aspent portion of the formation being processed.

[1523] Formation fluid produced from a formation during in situconversion may include carbon monoxide. Carbon monoxide produced fromthe formation may be used, for example, as a feedstock for a fuel cell,as a feedstock for a Fischer-Tropsch process, as a feedstock forproduction of methanol, and/or as a feedstock for production of methane.

[1524] Condensable hydrocarbons of formation fluids produced from aformation may be separated from the formation fluids. Formation fluidsmay be separated into a non-condensable portion (hydrocarbon andnon-hydrocarbon) and a condensable portion (hydrocarbon andnon-hydrocarbon). The condensable portion may include condensablehydrocarbons and compounds found in an aqueous phase. The aqueous phasemay be separated from the condensable component.

[1525] An aqueous phase may include ammonia. The ammonia content of thetotal produced fluids may be greater than about 0.1 weight % of thefluid, greater than about 0.5 weight % of the fluid, and, in someembodiments, up to about 10 weight % of the produced fluids. The ammoniamay be used to produce, for example, urea.

[1526] In certain embodiments, a fluid produced from a formation (e.g.,a coal formation) may include oxygenated hydrocarbons. For example,condensable hydrocarbons of the produced fluid may include an amount ofoxygenated hydrocarbons greater than about 5 weight % of the condensablehydrocarbons. Alternatively, the condensable hydrocarbons may include anamount of oxygenated hydrocarbons greater than about 0.1 weight % of thecondensable hydrocarbons. Furthermore, the condensable hydrocarbons mayinclude an amount of oxygenated hydrocarbons greater than about 1.0weight % of the condensable hydrocarbons or greater than about 2.0weight % of the condensable hydrocarbons. The oxygenated hydrocarbonsmay include, but are not limited to, phenol and/or substituted phenols.In some embodiments, phenol and substituted phenols may have moreeconomic value than many other products produced from an in situconversion process. Therefore, an in situ conversion process may beutilized to produce phenol and/or substituted phenols. For example,generation of phenol and/or substituted phenols may increase when afluid pressure within the formation is maintained at a lower pressure.

[1527] In some in situ conversion process embodiments, condensablehydrocarbons of a fluid produced from a hydrocarbon containing formationmay include olefins. For example, an olefin content of the condensablehydrocarbons may be in a range from about 0.1 weight % to about 15weight %. Alternatively, an olefin content of the condensablehydrocarbons may be within a range from about 0.1 weight % to about 5weight %. An olefin content of the condensable hydrocarbons may also bewithin a range from about 0.1 weight % to about 2.5 weight %. An olefincontent of the condensable hydrocarbons may be altered and/or controlledby controlling a pressure and/or a temperature within the formation. Forexample, olefin content of the condensable hydrocarbons may be reducedby selectively increasing pressure within the formation, by selectivelydecreasing temperature within the formation, by selectively reducingheating rates within the formation, and/or by selectively increasinghydrogen partial pressures in the formation. In some in situ conversionprocess embodiments, a reduced olefin content of the condensablehydrocarbons may be desired. For example, if a portion of the producedfluids is used to produce motor fuels, a reduced olefin content may bedesired.

[1528] In some in situ conversion process embodiments, a higher olefincontent may be desired. For example, if a portion of the condensablehydrocarbons may be sold, a higher olefin content may be selected due toa high economic value of olefin products. In some embodiments, olefinsmay be separated from the produced fluids and then sold and/or used as afeedstock for the production of other compounds.

[1529] Non-condensable hydrocarbons of a produced fluid may includeolefins. An ethene/ethane molar ratio may be used as an estimate ofolefin content of non-condensable hydrocarbons. In certain in situconversion process embodiments, the ethene/ethane molar ratio may rangefrom about 0.001 to about 0.15.

[1530] Fluid produced from a hydrocarbon containing formation mayinclude aromatic compounds. For example, the condensable hydrocarbonsmay include an amount of aromatic compounds greater than about 20 weight% or about 25 weight % of the condensable hydrocarbons. Alternatively,the condensable hydrocarbons may include an amount of aromatic compoundsgreater than about 30 weight % of the condensable hydrocarbons. Thecondensable hydrocarbons may also include relatively low amounts ofcompounds with more than two rings in them (e.g., tri-aromatics orabove). For example, the condensable hydrocarbons may include less thanabout 1 weight % or less than about 2 weight % of tri-aromatics or abovein the condensable hydrocarbons. Alternatively, the condensablehydrocarbons may include less than about 5 weight % of tri-aromatics orabove in the condensable hydrocarbons.

[1531] Fluid produced from a hydrocarbon containing formation mayinclude a small amount of asphaltenes (i.e., large multi-ring aromaticsthat may be substantially soluble in hydrocarbons) as compared to fluidproduced from a formation using other techniques such as fire floodsand/or steam floods. Temperature and pressure control within a selectedportion may inhibit the production of asphaltenes using an in situconversion process. Some asphaltenes may be entrained in formation fluidproduced from the formation. Asphaltenes may make up less than about 0.3weight % of the condensable hydrocarbons produced using an in situconversion process. In some in situ conversion process embodiments,asphaltenes may be less than 0.1 weight %, 0.05 weight %, or 0.01 weight%. In some in situ conversion process embodiments, the in situconversion process may result in no, or substantially no, asphalteneproduction, especially if initial production from the formation isinhibited or if initial production is ignored until the formationproduces hydrocarbons of a minimum quality.

[1532] Condensable hydrocarbons of a produced fluid may includerelatively large amounts of cycloalkanes. Linear chain molecules mayform ring compounds (e.g., hexane may form cyclohexane) in theformation. In addition, some aromatic compounds may be hydrogenated inthe formation to produce cycloalkanes (e.g., benzene may be hydrogenatedto form cyclohexane). The condensable hydrocarbons may include acycloalkane component of from about 0 weight % to about 30 weight %. Insome in situ conversion process embodiments, the condensablehydrocarbons may include a cycloalkane component from about 1% to about20%, or from about 5% to about 20%.

[1533] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing nitrogen. For example, less than about 1weight % (when calculated on an elemental basis) of the condensablehydrocarbons may be nitrogen (e.g., typically the nitrogen may be innitrogen containing compounds such as pyridines, amines, amides,carbazoles, etc.). The amount of nitrogen containing compounds maydepend on the amount of nitrogen in the initial hydrocarbon materialpresent in the formation.

[1534] Some of the nitrogen in the initial hydrocarbon material presentmay be produced as ammonia. Produced ammonia may be separated fromhydrocarbons. The ammonia may be separated, along with water, fromformation fluid produced from the formation. Formation fluid producedfrom the formation may include about 0.05 weight % or more of ammonia.Certain formations (e.g., coal and/or oil shale) may produce largeramounts of ammonia (e.g., up to about 10 weight % of the total fluidproduced may be ammonia).

[1535] In certain in situ conversion process embodiments, thecondensable hydrocarbons of a fluid produced from a formation mayinclude compounds containing oxygen. For example, in certain embodiments(e.g., for oil shale and heavy hydrocarbons), less than about 1 weight %(when calculated on an elemental basis) of the condensable hydrocarbonsmay be oxygen containing compounds (e.g., typically the oxygen may be inoxygen containing compounds such as phenol, substituted phenols,ketones, etc.). In some in situ conversion process embodiments (e.g.,for coal formations), between about 1 weight % and about 30 weight % ofthe condensable hydrocarbons may typically include oxygen containingcompounds such as phenols, substituted phenols, ketones, etc. In someinstances, certain compounds containing oxygen (e.g., phenols) may bevaluable and, as such, may be economically separated from the producedfluid. Other types of formations (e.g., tar sands formations or othermature hydrocarbon containing formations) may contain insignificant orno oxygen containing compounds in the initial hydrocarbon material. Suchformations may not produce any or only insignificant amounts ofoxygenated compounds. Some of the oxygen in the initial hydrocarbonmaterial may be produced as carbon dioxide.

[1536] In some in situ conversion process embodiments, condensablehydrocarbons of the fluid produced from a formation may includecompounds containing sulfur. For example, less than about 1 weight %(when calculated on an elemental basis) of the condensable hydrocarbonsmay be sulfur containing compounds. Typical sulfur containing compoundsmay include compounds such as thiophenes, mercaptans, etc. The amount ofsulfur containing compounds may depend on the amount of sulfur in theinitial hydrocarbon material present in the formation. Some of thesulfur in the initial hydrocarbon material present may be produced ashydrogen sulfide.

[1537] In some in situ conversion process embodiments, formation fluidproduced from the formation may include molecular hydrogen (H₂).Hydrogen may be from about 0.1 volume % to about 80 volume % of anon-condensable component of formation fluid produced from theformation. In some in situ conversion process embodiments, H₂ may beabout 5 volume % to about 70 volume % of the non-condensable componentof formation fluid produced from the formation. The amount of hydrogenin the formation fluid may be strongly dependent on the temperature ofthe formation. A high formation temperature may result in the productionof significant amounts of hydrogen. A high temperature may also resultin the formation of a significant amount of coke within the formation.

[1538] In some in situ conversion process embodiments, a large portionof the total organic carbon content of a formation may be converted intohydrocarbon fluids. In some embodiments, up to about 20 weight % of thetotal organic carbon content of hydrocarbons in the portion may betransformed into hydrocarbon fluids. In some in situ conversion processembodiments, the weight percentage of total organic carbon content ofhydrocarbons in the portion removed during the in situ process may besignificantly increased if synthesis gas is generated within theportion.

[1539] A total potential amount of products that may be produced fromhydrocarbons may be determined by a Fischer Assay. A Fischer Assay is astandard method that involves heating a sample of hydrocarbons toapproximately 500° C. in one hour, collecting products produced from theheated sample, and quantifying the products. In an embodiment, a methodfor treating a hydrocarbon containing formation in situ may includeheating a section of the formation to yield greater than about 60 weight% of the potential amount of products from the hydrocarbons as measuredby the Fischer Assay.

[1540] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20 weight % (orin some embodiments about 25 weight %) of the hydrocarbons within theselected section of the formation. Conversion of selected portions ofhydrocarbon layers within a formation may be avoided to inhibitsubsidence of the formation.

[1541] Heating at least a portion of a formation may cause some of thehydrocarbons within the portion to pyrolyze. Pyrolyzation may generatehydrocarbon fragments. The hydrocarbon fragments may be reactive and mayreact with other compounds in the formation and/or with otherhydrocarbon fragments produced by pyrolysis. Reaction of the hydrocarbonfragments with other compounds and/or with each other, however, mayreduce production of a selected product. A reducing agent in, orprovided to, the portion of the formation during heating may increaseproduction of the selected product. The reducing agent may be, but isnot limited to, H₂, methane, and/or other non-condensable hydrocarbonfluids.

[1542] In an in situ conversion process embodiment, molecular hydrogenmay be provided to the formation to create a reducing environment.Hydrogenation reactions between the molecular hydrogen and some of thehydrocarbons within a portion of the formation may generate heat. Theheat may heat the portion of the formation. Molecular hydrogen may alsobe generated within the portion of the formation. The generated H₂ mayhydrogenate hydrocarbon fluids within a portion of a formation. Thehydrogenation may generate heat that transfers to the formation tomaintain a desired temperature within the formation.

[1543] H₂ may be produced from a first portion of a hydrocarboncontaining formation. The H₂ may be separated from formation fluidproduced from the first portion. The H₂ from the first portion, alongwith other reducing or substantially inert fluid (e.g., methane, ethane,and/or nitrogen), may be provided to a second portion of the formationto create a reducing environment within the second portion. The secondportion of the formation may be heated by heat sources. Power input intothe heat sources may be reduced after introduction of H₂ due to heatingof the formation by hydrogenation reactions within the formation. H₂ maybe introduced into the formation continuously or batchwise.

[1544] Hydrogen introduced into the second portion of the formation mayreduce (e.g., at least partially saturate) some pyrolyzation fluid beingproduced or present in the second section. Reducing the pyrolyzationfluid may decrease a concentration of olefins in the pyrolyzationfluids. Reducing the pyrolysis products may improve the product qualityof the hydrocarbon fluids.

[1545] An in situ conversion process may generate significant amounts ofH₂ and hydrocarbon fluids within the formation. Generation of hydrogenwithin the formation, and pressure within the formation sufficient toforce hydrogen into a liquid phase within the formation, may produce areducing environment within-the formation without the need to introducea reducing fluid (e.g., H₂ and/or non-condensable saturatedhydrocarbons) into the formation. A hydrogen component of formationfluid produced from the formation may be separated and used for desiredpurposes. The desired purposes may include, but are not limited to, fuelfor fuel cells, fuel for combustors, and/or a feed stream for surfacehydrogenation units.

[1546] In an in situ conversion process embodiment, heating theformation may result in an increase in the thermal conductivity of aselected section of the heated portion. For example, porosity andpermeability within a selected section of the portion may increasesubstantially during heating such that heat may be transferred throughthe formation not only by conduction, but also by convection and/or byradiation from a heat source. Such radiant and convective transfer ofheat may increase an apparent thermal conductivity of the selectedsection and, consequently, the thermal diffusivity. The large apparentthermal diffusivity may make heating at least a portion of a hydrocarboncontaining formation from heat sources feasible. For example, acombination of conductive, radiant, and/or convective heating mayaccelerate heating. Such accelerated heating may significantly decreasea time required for producing hydrocarbons and may significantlyincrease the economic feasibility of commercialization of the in situconversion process.

[1547] In some in situ conversion process embodiments for treating coalformations, the in situ conversion process may increase the rank levelof coal within a heated portion of the coal. The increase in rank levelof the coal, as assessed by the vitrinite reflectance, may coincide witha substantial change of the structure (e.g., molecular changes in thecarbon structure) of the coal. The changed structure of the coal mayhave a higher thermal conductivity.

[1548] Thermal conductivity and thermal diffusivity within a hydrocarboncontaining formation may vary depending on, for example, a density ofthe hydrocarbon containing formation, a heat capacity of the formation,and a thermal conductivity of the formation. As pyrolysis occurs withina selected section, a portion of hydrocarbon containing mass may beremoved from the selected section. The removal of mass may include, butis not limited to, removal of water and a transformation of hydrocarbonsto formation fluids. A lower thermal conductivity may be expected aswater is removed from a hydrocarbon containing formation. Reduction ofthermal conductivity may be a function of depth of hydrocarbons in theformation. Lithostatic pressure may increase with depth. Deep in aformation, lithostatic pressure may close certain types of openings(e.g., cleats and/or fractures) in the formation. The closure of theformation openings may result in a decreased or minimal effect of massremoval from the formation on thermal conductivity and thermaldiffusivity.

[1549] In some in situ conversion process embodiments, the in situconversion process may generate molecular hydrogen during the pyrolysisprocess. In addition, pyrolysis tends to increase the porosity/voidspaces in the formation. Void spaces in the formation may containhydrogen gas generated by the pyrolysis process. Hydrogen gas may haveabout six times the thermal conductivity of nitrogen or air. Thepresence of hydrogen in void spaces may raise the thermal conductivityof the formation and decrease the effect of mass removal from theformation on thermal conductivity.

[1550] Some in situ conversion process embodiments may be able toeconomically treat formations that were previously believed to beuneconomical to produce. Recovery of hydrocarbons from previouslyuneconomically producible formations may be possible because of thesurprising increases in thermal conductivity and thermal diffusivitythat can be achieved during thermal conversion of hydrocarbons withinthe formation by conductively and/or radiatively heating a portion ofthe formation. Surprising results are illustrated by the fact that priorliterature indicated that certain hydrocarbon containing formations,such as coal, exhibited relatively low values for thermal conductivityand thermal diffusivity when heated. For example, in government reportNo. 8364 by J. M. Singer and R. P. Tye entitled “Thermal, Mechanical,and Physical Properties of Selected Bituminous Coals and Cokes,” U.S.Department of the Interior, Bureau of Mines (1979), the authors reportthe thermal conductivity and thermal diffusivity for four bituminouscoals. This government report includes graphs of thermal conductivityand diffusivity that show relatively low values up to about 400° C.(e.g., thermal conductivity is about 0.2 W/(m °C.) or below, and thermaldiffusivity is below about 1.7×10⁻³ cm²/s). This government reportstates: “coals and cokes are excellent thermal insulators.”

[1551] In certain in situ conversion process embodiments, hydrocarboncontaining resources (e.g., coal) may be treated such that the thermalconductivity and thermal diffusivity are significantly higher (e.g.,thermal conductivity at or above about 0.5 W/(m °C.) and thermaldiffusivity at or above 4.1×10⁻³ cm²/s) than would be expected based onprevious literature, such as government report No. 8364. If a coalformation is subjected to an in situ conversion process, the coal doesnot act as “an excellent thermal insulator.” Instead, heat can and doestransfer and/or diffuse into the formation at significantly higher (andbetter) rates than would be expected according to the literature,thereby significantly enhancing economic viability of treating theformation.

[1552] In an in situ conversion process embodiment, heating a portion ofa hydrocarbon containing formation in situ to a temperature less than anupper pyrolysis temperature may increase permeability of the heatedportion. Permeability may increase due to formation of thermal fractureswithin the heated portion. Thermal fractures may be generated by thermalexpansion of the formation and/or by localized increases in pressure dueto vaporization of liquids (e.g., water and/or hydrocarbons) in theformation. As a temperature of the heated portion increases, water inthe formation may be vaporized. The vaporized water may escape and/or beremoved from the formation. Removal of water may also increase thepermeability of the heated portion. In addition, permeability of theheated portion may also increase as a result of mass loss from theformation due to generation of pyrolysis fluids in the formation.Pyrolysis fluid may be removed from the formation through productionwells.

[1553] Heating the formation from heat sources placed in the formationmay allow a permeability of the heated portion of a hydrocarboncontaining formation to be substantially uniform. A substantiallyuniform permeability may inhibit channeling of formation fluids in theformation and allow production from substantially all portions of theheated formation. An assessed (e.g., calculated or estimated)permeability of any selected portion in the formation having asubstantially uniform permeability may not vary by more than a factor of10 from an assessed average permeability of the selected portion.

[1554] Permeability of a selected section within the heated portion ofthe hydrocarbon containing formation may rapidly increase when theselected section is heated by conduction. A permeability of animpermeable hydrocarbon containing formation may be less than about 0.1millidarcy (9.9×10⁻¹⁷ m²) before treatment. In some embodiments,pyrolyzing at least a portion of a hydrocarbon containing formation mayincrease a permeability within a selected section of the portion togreater than about 10 millidarcy, 100 millidarcy, 1 darcy, 10 darcy, 20darcy, or 50 darcy. A permeability of a selected section of the portionmay increase by a factor of more than about 100, 1,000, 10,000, 100,000or more.

[1555] In some in situ conversion process embodiments, superposition(e.g., overlapping influence) of heat from one or more heat sources mayresult in substantially uniform heating of a portion of a hydrocarboncontaining formation. Since formations during heating will typicallyhave a temperature gradient that is highest near heat sources andreduces with increasing distance from the heat sources, “substantiallyuniform” heating means heating such that temperature in a majority ofthe section does not vary by more than 100° C. from an assessed averagetemperature in the majority of the selected section (volume) beingtreated.

[1556] Removal of hydrocarbons from the formation during an in situconversion process may occur on a microscopic scale, as well as amacroscopic scale (e.g., through production wells). Hydrocarbons may beremoved from micropores within a portion of the formation due toheating. Micropores may be generally defined as pores having across-sectional dimension of less than about 1000 Å. Removal of solidhydrocarbons may result in a substantially uniform increase in porositywithin at least a selected section of the heated portion. Heating theportion of a hydrocarbon containing formation may substantiallyuniformly increase a porosity of a selected section within the heatedportion. “Substantially uniform porosity” means that the assessed (e.g.,calculated or estimated) porosity of any selected portion in theformation does not vary by more than about 25% from the assessed averageporosity of such selected portion.

[1557] Physical characteristics of a portion of a hydrocarbon containingformation after pyrolysis may be similar to those of a porous bed. Thephysical characteristics of a formation subjected to an in situconversion process may significantly differ from physicalcharacteristics of a hydrocarbon containing formation subjected toinjection of gases that burn hydrocarbons to heat the hydrocarbons andor to formations subjected to steam flood production. Gases injectedinto virgin or fractured formations may channel through the formation.The gases may not be uniformly distributed throughout the formation. Incontrast, a gas injected into a portion of a hydrocarbon containingformation subjected to an in situ conversion process may readily andsubstantially uniformly contact the carbon and/or hydrocarbons remainingin the formation. Gases produced by heating the hydrocarbons may betransferred a significant distance within the heated portion of theformation with minimal pressure loss.

[1558] Transfer of gases in a formation over significant distances maybe particularly advantageous to reduce the number of production wellsneeded to produce formation fluid from the formation. A first portion ofa hydrocarbon containing formation may be subjected to an in situconversion process. The volume of the formation subjected to in situconversion may be expanded by heating abutting portions of thehydrocarbon containing formation. Formation fluid produced in theabutting portions of the formation may be produced from production wellsin the first portion. If needed, a few additional production wells maybe installed in the abutting portions of formation, but such productionwells may have large separation distances. The ability to transfer fluidin a formation over long distances may be advantageous for treating asteeply dipping hydrocarbon containing formation. Production wells maybe placed in an upper portion of the dipping hydrocarbon production.Heat sources may be inserted into the steeply dipping formation. Theheat sources may follow the dip of the formation. The upper portion maybe subjected to thermal treatment by activating portions of the heatsources in the upper portion. Abutting portions of the steeply dippingformation may be subjected to thermal treatment after treatment in theupper portion increases the permeability of the formation so that fluidsin lower portions may be produced from the upper portions.

[1559] Synthesis gas may be produced from a portion of a hydrocarboncontaining formation. Synthesis gas may be produced from coal, oilshale, other kerogen containing formations, heavy hydrocarbons (tarsands, etc.), and other bitumen containing formations. The hydrocarboncontaining formation may be heated prior to synthesis gas generation toproduce a substantially uniform, relatively high permeability formation.In an in situ conversion process embodiment, synthesis gas productionmay be commenced after production of pyrolysis fluids has been exhaustedor becomes uneconomical. Alternately, synthesis gas generation may becommenced before substantial exhaustion or uneconomical pyrolysis fluidproduction has been achieved if production of synthesis gas will be moreeconomically favorable. Formation temperatures will usually be higherthan pyrolysis temperatures during synthesis gas generation. Raising theformation temperature from pyrolysis temperatures to synthesis gasgeneration temperatures allows further utilization of heat applied tothe formation to pyrolyze the formation. While raising a temperature ofa formation from pyrolysis temperatures to synthesis gas temperatures,methane and/or H₂ may be produced from the formation.

[1560] Producing synthesis gas from a formation from which pyrolyzationfluids have been previously removed allows a synthesis gas to beproduced that includes mostly H₂, CO, water, and/or CO₂. Producedsynthesis gas, in certain embodiments, may have substantially nohydrocarbon component unless a separate source hydrocarbon stream isintroduced into the formation with or in addition to the synthesis gasproducing fluid. Producing synthesis gas from a substantially uniform,relatively high permeability formation that was formed by slowly heatinga formation through pyrolysis temperatures may allow for easyintroduction of a synthesis gas generating fluid into the formation, andmay allow the synthesis gas generating fluid to contact a relativelylarge portion of the formation. The synthesis gas generating fluid cando so because the permeability of the formation has been increasedduring pyrolysis and/or because the surface area per volume in theformation has increased during pyrolysis. The relatively large surfacearea (e.g., “contact area”) in the post-pyrolysis formation tends toallow synthesis gas generating reactions to be substantially atequilibrium conditions for C, H₂, CO, water, and CO₂. Reactions in whichmethane is formed may, however, not be at equilibrium because they arekinetically limited. The relatively high, substantially uniformformation permeability may allow production wells to be spaced fartherapart than production wells used during pyrolysis of the formation.

[1561] A temperature of at least a portion of a formation that is usedto generate synthesis gas may be raised to a synthesis gas generatingtemperature (e.g., between about 400° C. and about 1200° C.). In someembodiments, composition of produced synthesis gas may be affected byformation temperature, by the temperature of the formation adjacent tosynthesis gas production wells, and/or by residence time of thesynthesis gas components. A relatively low synthesis gas generationtemperature may produce a synthesis gas having a high H₂ to CO ratio,but the produced synthesis gas may also include a large portion of othergases such as water, CO₂, and methane. A relatively high formationtemperature may produce a synthesis gas having a H₂ to CO ratio thatapproaches 1, and the stream may include mostly and, in some cases, onlyH₂ and CO. If the synthesis gas generating fluid is substantially puresteam, then the H₂ to CO ratio may approach 1 at relatively hightemperatures. At a formation temperature of about 700° C., the formationmay produce a synthesis gas with a H₂ to CO ratio of about 2 at acertain pressure. The composition of the synthesis gas tends to dependon the nature of the synthesis gas generating fluid.

[1562] Synthesis gas generation is generally an endothermic process.Heat may be added to a portion of a formation during synthesis gasproduction to keep formation temperature at a desired synthesis gasgenerating temperature or above a minimum synthesis gas generatingtemperature. Heat may be added to the formation from heat sources, fromoxidation reactions within the portion, and/or from introducingsynthesis gas generating fluid into the formation at a highertemperature than the temperature of the formation.

[1563] An oxidant may be introduced into a portion of the formation withsynthesis gas generating fluid. The oxidant may exothermically reactwith carbon within the portion of the formation to heat the formation.Oxidation of carbon within a formation may allow a portion of aformation to be economically heated to relatively high synthesis gasgenerating temperatures. The oxidant may be introduced into theformation without synthesis gas generating fluid to heat the portion.Using an oxidant, or an oxidant and heat sources, to heat the portion ofthe formation may be significantly more favorable than heating theportion of the formation with only the heat sources. The oxidant may be,but is not limited to, air, oxygen, or oxygen enriched air. The oxidantmay react with carbon in the formation to produce CO₂ and/or CO. The useof air, or oxygen enriched air (i.e., air with an oxygen content greaterthan 21 volume %), to generate heat within the formation may cause asignificant portion of N₂ to be present in produced synthesis gas.Temperatures in the formation may be maintained below temperaturesneeded to generate oxides of nitrogen (NO_(x)), so that little or noNO_(x) compounds may be present in produced synthesis gas.

[1564] A mixture of steam and oxygen, steam and enriched air, or steamand air, may be continuously injected into a formation. If injection ofsteam and oxygen or steam and enriched air is used for synthesis gasproduction, the oxygen may be produced on site (or near to the site) byelectrolysis of water utilizing direct current output of a fuel cell. H₂produced by the electrolysis of water may be used as a fuel stream forthe fuel cell. O₂ produced by the electrolysis of water may also beinjected into the hot formation to raise a temperature of the formation.

[1565] Heat sources and/or production wells within a formation forpyrolyzing and producing pyrolysis fluids from the formation may beutilized for different purposes during synthesis gas production. A wellthat was used as a heat source or a production well during pyrolysis maybe used as an injection well to introduce synthesis gas producing fluidinto the formation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a production well duringsynthesis gas generation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a heat source to heatthe formation during synthesis gas generation. Some production wellsused during a pyrolysis phase may be shut in. Synthesis gas productionwells may be spaced further apart than pyrolysis production wellsbecause of the relatively high, substantially uniform permeability ofthe formation. Some production wells used during a pyrolysis phase maybe shut in or converted to other uses. Synthesis gas production wellsmay be heated to relatively high temperatures so that a portion of theformation adjacent to the production well is at a temperature that willproduce a desired synthesis gas composition. Comparatively, pyrolysisfluid production wells may not be heated at all, or may only be heatedto a temperature that will inhibit condensation of pyrolysis fluidwithin the production well.

[1566] Synthesis gas may be produced from a dipping formation from wellsused during pyrolysis of the formation. As shown in FIG. 9, productionwells 512 used for synthesis gas production may be located above anddown dip from heater well 520. In some embodiments, heater well 520 maybe used as an injection well. Hot synthesis gas producing fluid may beintroduced into heater well 520. Hot synthesis gas fluid that moves downdip may generate synthesis gas that is produced through production wells512. Synthesis gas generating fluid that moves up dip may generatesynthesis gas in a portion of the formation that is at synthesis gasgenerating temperatures. A portion of the synthesis gas generating fluidand generated synthesis gas that moves up dip above the portion of theformation at synthesis gas generating temperatures may heat adjacentportions of the formation. The synthesis gas generating fluid that movesup dip may condense, heat adjacent portions of formation, and flowdownwards towards or into a portion of the formation at synthesis gasgenerating temperature. The synthesis gas generating fluid may thengenerate additional synthesis gas.

[1567] Synthesis gas generating fluid may be any fluid capable ofgenerating H₂ and CO within a heated portion of a formation. Synthesisgas generating fluid may include water, O₂, air, CO₂, hydrocarbonfluids, or combinations thereof. Water may be introduced into aformation as a liquid or as steam. Water may react with carbon in aformation to produce H₂, CO, and CO₂. CO₂ may react with hot carbon toform CO. Air and O₂ may be oxidants that react with carbon in aformation to generate heat and form CO₂, CO, and other compounds.Hydrocarbon fluids may react within a formation to form H₂, CO, CO₂,H₂O, coke, methane, and/or other light hydrocarbons. Introducing lowcarbon number hydrocarbons (i.e., compounds with carbon numbers lessthan 5) may produce additional H₂ within the formation. Adding highercarbon number hydrocarbons to the formation may increase an energycontent of generated synthesis gas by having a significant methane andother low carbon number compounds fraction within the synthesis gas.

[1568] Water provided as a synthesis gas generating fluid may be derivedfrom numerous different sources. Water may be produced during apyrolysis stage of treating a formation. The water may include someentrained hydrocarbon fluids. Such fluid may be used as synthesis gasgenerating fluid. Water that includes hydrocarbons may advantageouslygenerate additional H₂ when used as a synthesis gas generating fluid.Water produced from water pumps that inhibit water flow into a portionof formation being subjected to an in situ conversion process mayprovide water for synthesis gas generation. A low rank kerogen resourceor hydrocarbons having a relatively high water content (i.e., greaterthan about 20 weight % H₂O) may generate a large amount of water and/orCO₂ if subjected to an in situ conversion process. The water and CO₂produced by subjecting a low rank kerogen resource to an in situconversion process may be used as a synthesis gas generating fluid.

[1569] Reactions involved in the formation of synthesis gas may include,but are not limited to:

C+H₂O

H₂+CO  (54)

C+2H₂O

2H₂+CO₂  (55)

C+CO₂

2CO  (56)

[1570] Thermodynamics also allows the following reactions to proceed:

2C+2H₂O

CH₄+CO₂  (57)

C+2H₂

CH₄  (58)

[1571] However, kinetics of the reactions are slow in certainembodiments, so that relatively low amounts of methane are formed atformation conditions from Reactions 57 and 58.

[1572] In the presence of oxygen, the following reaction may take placeto generate carbon dioxide and heat:

C+O₂

CO₂  (59)

[1573] Equilibrium gas phase compositions of coal in contact with steammay provide an indication of the compositions of components produced ina formation during synthesis gas generation. Equilibrium compositiondata for H₂, carbon monoxide, and carbon dioxide may be used todetermine appropriate operating conditions (e.g., temperature) that maybe used to produce a synthesis gas having a selected composition.Equilibrium conditions may be approached within a formation due to ahigh, substantially uniform permeability of the formation. Compositiondata obtained from synthesis gas production may in many in situconversion process embodiments, deviate by less than 10% fromequilibrium values.

[1574] In one synthesis gas production embodiment, a composition of theproduced synthesis gas can be changed by injecting additional componentsinto the formation along with steam. Carbon dioxide may be provided inthe synthesis gas generating fluid to inhibit production of carbondioxide from the formation during synthesis gas generation. The carbondioxide may shift the equilibrium of Reaction 55 to the left, thusreducing the amount of carbon dioxide generated from formation carbon.The carbon dioxide may also shift the equilibrium of Reaction 56 to theright to generate carbon monoxide. Carbon dioxide may be separated fromthe synthesis gas and may be re-injected into the formation with thesynthesis gas generating fluid. Addition of carbon dioxide in thesynthesis gas generating fluid may, however, reduce the production ofhydrogen.

[1575]FIG. 117 depicts a schematic diagram of use of water recoveredfrom pyrolysis fluid production to generate synthesis gas. Heat source508 with electric heater 1132 produces pyrolysis fluid 1484 from firstsection 1486 of the formation. Produced pyrolysis fluid 1484 may be sentto separator 1488. Separator 1488 may include a number of individualseparation units and processing units that produce aqueous stream 1490,vapor stream 1492, and hydrocarbon condensate stream 1494. Aqueousstream 1490 from separator 1488 may be combined with synthesis gasgenerating fluid 1496 to form synthesis gas generating fluid 1498.Synthesis gas generating fluid 1498 may be provided to injection well606 and introduced to second portion 1500 of the formation. Synthesisgas 1502 may be produced from production well 512.

[1576]FIG. 118 depicts a schematic diagram of an embodiment of a systemfor synthesis gas production. Synthesis gas 1502 may be produced fromformation 678 through production well 512. Gas separation unit 1504 mayseparate a portion of carbon dioxide from synthesis gas 1502 to produceCO₂ stream 1506 and remaining synthesis gas stream 1502A. CO₂ stream1506 may be mixed with synthesis gas generating fluid 1496 that isintroduced into formation 678 through injection well 606. In somesynthesis gas process embodiments, CO₂ may be introduced into theformation separate from synthesis gas producing fluid. Introducing CO₂may inhibit conversion of carbon within the formation to CO₂ and/or mayincrease an amount of CO generated within the formation.

[1577] Synthesis gas generating fluid may be introduced into a formationin a variety of different ways. Steam may be injected into a heatedhydrocarbon containing formation at a lowermost portion of the heatedformation. Alternatively, in a steeply dipping formation, steam may beinjected up dip with synthesis gas production down dip. The injectedsteam may pass through the remaining hydrocarbon containing formation toa production well. In addition, endothermic heat of reaction may beprovided to the formation with heat sources disposed along a path of theinjected steam. In some embodiments, steam may be injected at aplurality of locations along the hydrocarbon containing formation toincrease penetration of the steam throughout the formation. A line drivepattern of locations may also be utilized. The line drive pattern mayinclude alternating rows of steam injection wells and synthesis gasproduction wells.

[1578] Synthesis gas reactions may be slow at relatively low pressuresand at temperatures below about 400° C. At relatively low pressures, andtemperatures between about 400° C. and about 700° C., Reaction 55 maypredominate so that synthesis gas composition is primarily hydrogen andcarbon dioxide. At relatively low pressures and temperatures greaterthan about 700° C., Reaction 54 may predominate so that synthesis gascomposition is primarily hydrogen and carbon monoxide.

[1579] Advantages of a lower temperature synthesis gas reaction mayinclude lower heat requirements, cheaper metallurgy, and lessendothermic reactions (especially when methane formation takes place).An advantage of a higher temperature synthesis gas reaction is thathydrogen and carbon monoxide may be used as feedstock for otherprocesses (e.g., Fischer-Tropsch processes).

[1580] A pressure of the hydrocarbon containing formation may bemaintained at relatively high pressures during synthesis gas production.The pressure may range from atmospheric pressure to a pressure thatapproaches a lithostatic pressure of the formation. Higher formationpressures may allow generation of electricity by passing producedsynthesis gas through a turbine. Higher formation pressures may allowfor smaller collection conduits to transport produced synthesis gas andreduced downstream compression requirements on the surface.

[1581] In some synthesis gas process embodiments, synthesis gas may beproduced from a portion of a formation in a substantially continuousmanner. The portion may be heated to a desired synthesis gas generatingtemperature. A synthesis gas generating fluid may be introduced into theportion. Heat may be added to, or generated within, the portion of theformation during introduction of the synthesis gas generating fluid tothe portion. The added heat may compensate for the loss of heat due tothe endothermic synthesis gas reactions as well as heat losses to a toplayer (overburden), bottom layer (underburden), and unreactive materialin the portion.

[1582]FIG. 119 illustrates a schematic representation of an embodimentof a continuous synthesis gas production system. FIG. 119 includes aformation with heat injection wellbore 1336A and heat injection wellbore1336B. The wellbores may be members of a larger pattern of wellboresplaced throughout a portion of the formation. The portion of theformation may be heated to synthesis gas generating temperatures byheating the formation with heat sources, by injecting an oxidizingfluid, or by a combination thereof. Oxidizing fluid 1096 (e.g., air,enriched air, or oxygen) and synthesis gas generating fluid 1498 (e.g.,water, or steam) may be injected into wellbore 1336A. In a synthesis gasprocess embodiment that uses oxygen and steam, the ratio of oxygen tosteam may range from approximately 1:2 to approximately 1:10, orapproximately 1:3 to approximately 1:7 (e.g., about 1:4).

[1583] In situ combustion of hydrocarbons may heat region 1508 of theformation between wellbores 1336A and 1336B. Injection of the oxidizingfluid may heat region 1508 to a particular temperature range, forexample, between about 600° C. and about 700° C. The temperature mayvary, however, depending on a desired composition of the synthesis gas.An advantage of the continuous production method may be that atemperature gradient established across region 1508 may be substantiallyuniform and substantially constant with time once the formationapproaches thermal equilibrium. Continuous production may also eliminatea need for use of valves to reverse injection directions on a frequentbasis. Further, continuous production may reduce temperatures near theinjection wells due to endothermic cooling from the synthesis gasreaction that occur in the same region as oxidative heating. Thesubstantially constant temperature gradient may allow for control ofsynthesis gas composition. Produced synthesis gas 1502 may exitcontinuously from wellbore 1336B.

[1584] In a synthesis gas process embodiment, oxygen may be used insteadof air as oxidizing fluid 1096 in continuous production. If air is used,nitrogen may need to be separated from the produced synthesis gas. Theuse of oxygen as oxidizing fluid 1096 may increase a cost of productiondue to the cost of obtaining substantially pure oxygen. The cryogenicnitrogen by-product obtained from an air separation plant used toproduce the required oxygen may, however, be used in a heat exchangeunit to condense hydrocarbons from a hot vapor stream produced duringpyrolysis of hydrocarbons. The pure nitrogen may also be used forammonia production.

[1585] In some synthesis gas process embodiments, synthesis gas may beproduced in a batch manner from a portion of the formation. The portionof the formation may be heated, or heat may be generated within theportion, to raise a temperature of the portion to a high synthesis gasgenerating temperature. Synthesis gas generating fluid may then be addedto the portion until generation of synthesis gas reduces the temperatureof the formation below a temperature that produces a desired synthesisgas composition. Introduction of the synthesis gas generating fluid maythen be stopped. The cycle may be repeated by reheating the portion ofthe formation to the high synthesis gas generating temperature andadding synthesis gas generating fluid after obtaining the high synthesisgas generating temperature. Composition of generated synthesis gas maybe monitored to determine when addition of synthesis gas generatingfluid to the formation should be stopped.

[1586]FIG. 120 illustrates a schematic representation of an embodimentof a batch production of synthesis gas in a hydrocarbon containingformation. Wellbore 1336A and wellbore 1336B may be located within aportion of the formation. The wellbores may be members of a largerpattern of wellbores throughout the portion of the formation. Oxidizingfluid 1096, such as air or oxygen, may be injected into wellbore 1336A.Oxidation of hydrocarbons may heat region 1510 of a formation betweenwellbores 1336A and 1336B. Injection of air or oxygen may continue untilan average temperature of region 1510 is at a desired temperature (e.g.,between about 900° C. and about 1000° C.). Higher or lower temperaturesmay also be developed. A temperature gradient may be formed in region1510 between wellbore 1336A and wellbore 1336B. The highest temperatureof the gradient may be located proximate injection wellbore 1336A.

[1587] When a desired temperature has been reached, or when oxidizingfluid has been injected for a desired period of time, oxidizing fluidinjection may be lessened and/or ceased. Synthesis gas generating fluid1498, such as steam or water, may be injected into injection wellbore1336B to produce synthesis gas. A back pressure of the injected steam orwater in the injection wellbore may force the synthesis gas produced andun-reacted steam across region 1510. A decrease in average temperatureof region 1510 caused by the endothermic synthesis gas reaction may bepartially offset by the temperature gradient in region 1510 in adirection indicated by arrow 1512. Synthesis gas 1502 may be producedthrough heat source wellbore 1336A. If the composition of the productdeviates from a desired composition, then steam injection may cease, andair or oxygen injection may be reinitiated.

[1588] Synthesis gas of a selected composition may be produced byblending synthesis gas produced from different portions of theformation. A first portion of a formation may be heated by one or moreheat sources to a first temperature sufficient to allow generation ofsynthesis gas having a H₂ to carbon monoxide ratio of less than theselected H₂ to carbon monoxide ratio (e.g., about 1:1 or 2:1). A firstsynthesis gas generating fluid may be provided to the first portion togenerate a first synthesis gas. The first synthesis gas may be producedfrom the formation. A second portion of the formation may be heated byone or more heat sources to a second temperature sufficient to allowgeneration of synthesis gas having a H₂ to carbon monoxide ratio ofgreater than the selected H₂ to carbon monoxide ratio (e.g., a ratio of3:1 or more). A second synthesis gas generating fluid may be provided tothe second portion to generate a second synthesis gas. The secondsynthesis gas may be produced from the formation. The first synthesisgas may be blended with the second synthesis gas to produce a blendsynthesis gas having a desired H₂ to carbon monoxide ratio.

[1589] The first temperature may be different than the secondtemperature. Alternatively, the first and second temperatures may beapproximately the same temperature. For example, a temperaturesufficient to allow generation of synthesis gas having differentcompositions may vary depending on compositions of the first and secondportions and/or prior pyrolysis of hydrocarbons within the first andsecond portions. The first synthesis gas generating fluid may havesubstantially the same composition as the second synthesis gasgenerating fluid. Alternatively, the first synthesis gas generatingfluid may have a different composition than the second synthesis gasgenerating fluid. Appropriate first and second synthesis gas generatingfluids may vary depending upon, for example, temperatures of the firstand second portions, compositions of the first and second portions, andprior pyrolysis of hydrocarbons within the first and second portions.

[1590] In addition, synthesis gas having a selected ratio of H₂ tocarbon monoxide may be obtained by controlling the temperature of theformation. In one embodiment, the temperature of an entire portion orsection of the formation may be controlled to yield synthesis gas with aselected ratio. Alternatively, the temperature in or proximate asynthesis gas production well may be controlled to yield synthesis gaswith the selected ratio. Controlling temperature near a production wellmay be sufficient because synthesis gas reactions may be fast enough toallow reactants and products to approach equilibrium concentrations.

[1591] In a synthesis gas process, synthesis gas having a selected ratioof H₂ to carbon monoxide may be obtained by treating produced synthesisgas at the surface. First, the temperature of the formation may becontrolled to yield synthesis gas with a ratio different than a selectedratio. For example, the formation may be maintained at a relatively hightemperature to generate a synthesis gas with a relatively low H₂ tocarbon monoxide ratio (e.g., the ratio may approach 1 under certainconditions). Some or all of the produced synthesis gas may then beprovided to a shift reactor (shift process) at the surface. Carbonmonoxide reacts with water in the shift process to produce H₂ and carbondioxide. Therefore, the shift process increases the H₂ to carbonmonoxide ratio. The carbon dioxide may then be separated to obtain asynthesis gas having a selected H₂ to carbon monoxide ratio.

[1592] Produced synthesis gas 1502 may be used for production of energy.In FIG. 121, treated gases 1514 may be routed from treatment facility516 to energy generation unit 1516 for extraction of useful energy. Insome embodiments, energy may be extracted from the combustible gases inthe synthesis gas by oxidizing the gases to produce heat and convertinga portion of the heat into mechanical and/or electrical energy.Alternatively, energy generation unit 1516 may include a fuel cell thatproduces electrical energy. In addition, energy generation unit 1516 mayinclude, for example, a molten carbonate fuel cell or another type offuel cell, a turbine, a boiler firebox, or a downhole gas heater.Produced electrical energy 1518A may be supplied to power grid 1520. Aportion of produced electricity 1518B may be used to supply energy toelectric heaters 1132 that heat formation 678.

[1593] In one embodiment, energy generation unit 1516 may be a boilerfirebox. A firebox may include a small refractory-lined chamber, builtwholly or partly in the wall of a kiln, for combustion of fuel. Air oroxygen 1522 may be supplied to energy generation unit 1516 to oxidizethe produced synthesis gas. Water 1524 produced by oxidation of thesynthesis gas may be recycled to the formation to produce additionalsynthesis gas.

[1594] A portion of synthesis gas produced from a formation may, in someembodiments, be used for fuel in downhole gas heaters. Downhole gasheaters (e.g., flameless combustors, downhole combustors, etc.) may beused to provide heat to a hydrocarbon containing formation. In someembodiments, downhole gas heaters may heat portions of a formationsubstantially by conduction of heat through the formation. Providingheat from gas heaters may be primarily self-reliant and may reduce oreliminate a need for electric heaters. Because downhole gas heaters mayhave thermal efficiencies approaching 90%, the amount of carbon dioxidereleased to the environment by downhole gas heaters may be less than theamount of carbon dioxide released to the environment from a processusing fossil-fuel generated electricity to heat the hydrocarboncontaining formation.

[1595] Carbon dioxide may be produced during pyrolysis and/or duringsynthesis gas generation. Carbon dioxide may also be produced by energygeneration processes and/or combustion processes. Net release of carbondioxide to the atmosphere from an in situ conversion process forhydrocarbons may be reduced by utilizing the produced carbon dioxideand/or by storing carbon dioxide within the formation or within anotherformation. For example, a portion of carbon dioxide produced from theformation may be utilized as a flooding agent or as a feedstock forproducing chemicals.

[1596] In an in situ conversion process embodiment, an energy generationprocess may produce a reduced amount of emissions by sequestering carbondioxide produced during extraction of useful energy. For example,emissions from an energy generation process may be reduced by storingcarbon dioxide within a hydrocarbon containing formation. In an in situconversion process embodiment, the amount of stored carbon dioxide maybe approximately equivalent to that in an exit stream from theformation.

[1597]FIG. 121 illustrates a reduced emission energy process. Carbondioxide stream 1506 produced by energy generation unit 1516 may beseparated from fluids exiting the energy generation unit. Carbon dioxidemay be separated from H₂ at high temperatures by using a hot palladiumfilm supported on porous stainless steel or a ceramic substrate, or byusing high temperature and pressure swing adsorption. A portion or allof carbon dioxide stream 1506 may be sequestered in spent hydrocarboncontaining formation 1526, injected into oil producing fields 1528 forenhanced oil recovery by improving mobility and production of oil insuch fields, sequestered into a deep hydrocarbon containing formation1530 containing methane by adsorption and subsequent desorption ofmethane, or re-injected into a section of the formation through asynthesis gas production well to enhance production of carbon monoxide.Carbon dioxide leaving the energy generation unit may be sequestered ina dewatered coal bed methane reservoir. The water for synthesis gasgeneration may come from dewatering a coal bed methane reservoir.Additional methane may be produced by alternating carbon dioxide andnitrogen. An example of a method for sequestering carbon dioxide isillustrated in U.S. Pat. No. 5,566,756 to Chaback et al., which isincorporated by reference as if fully set forth herein. Additionalenergy may be utilized by removing heat from the carbon dioxide streamleaving the energy generation unit.

[1598] In an in situ conversion process embodiment, a hot spentformation may be cooled before being used to sequester carbon dioxide. Alarger quantity of carbon dioxide may be adsorbed in a coal formation ifthe coal formation is at ambient or near ambient temperature. Inaddition, cooling a formation may strengthen the formation. The spentformation may be cooled by introducing water into the formation. Thesteam produced may be removed from the formation through productionwells. The generated steam may be used for any desired process. Forexample, the steam may be provided to an adjacent portion of a formationto heat the adjacent portion or to generate synthesis gas.

[1599] In an in situ conversion process embodiment, a spent hydrocarboncontaining formation may be mined. In some embodiments, a coal formationmay be mined after region 2 heating (depicted in FIG. 1) withoutundergoing a synthesis gas generation phase. In some embodiments, a coalformation may be mined after undergoing synthesis gas generation duringregion 3 heating. The mined material may be used for metallurgicalpurposes such as a fuel for generating high temperatures duringproduction of steel. Pyrolysis of a coal formation may increase a rankof the coal. After pyrolysis, the coal may be transformed to a coalhaving characteristics of anthracite. A spent hydrocarbon containingformation may have a thickness of 30 m or more. In comparison,anthracite coal seams that are typically mined for metallurgical usesare typically about one meter or less in thickness.

[1600]FIG. 122 illustrates an in situ conversion process embodiment inwhich fluid produced from pyrolysis may be separated into a fuel cellfeed stream and fed into a fuel cell to produce electricity. Theembodiment may include hydrocarbon containing formation 678 withproduction well 512 that produces pyrolysis fluid. Heater well 520 withelectric heater 1132 may be a heat source that heats, or contributes toheating, the formation. Heater well 520 may also be a production wellused to produce pyrolysis fluid 1484. Pyrolysis fluid from heater well520 may include H₂ and hydrocarbons with carbon numbers less than 5.Larger chain hydrocarbons may be reduced to hydrocarbons with carbonnumbers less than 5 due to the heat adjacent to heater well 520.Pyrolysis fluid 1484 produced from heater well 520 may be fed to gasmembrane separation system 1532 to separate H₂ and hydrocarbons withcarbon numbers less than 5. Fuel cell feed stream 1534, which may besubstantially composed of H₂, may be fed into fuel cell 1536. Air feedstream 1538 may be fed into fuel cell 1536. Nitrogen stream 1540 may bevented from fuel cell 1536. Electricity 1518A produced from the fuelcell may be routed to a power grid. Electricity 1518B may be used topower electric heaters 1132 in heater wells 520. Carbon dioxide stream1506 produced in fuel cell 1536 may be injected into formation 678.

[1601] Hydrocarbons having carbon numbers of 4, 3, and 1 typically havefairly high market values. Separation and selling of these hydrocarbonsmay be desirable. Ethane (carbon number 2) may not be sufficientlyvaluable to separate and sell in some markets. Ethane may be sent aspart of a fuel stream to a fuel cell or ethane may be used as ahydrocarbon fluid component of a synthesis gas generating fluid. Ethanemay also be used as a feedstock to produce ethene. In some markets,there may be no market for any hydrocarbons having carbon numbers lessthan 5. In such a situation, all of the hydrocarbon gases producedduring pyrolysis may be sent to fuel cells, used as fuels, and/or beused as hydrocarbon fluid components of a synthesis gas generatingfluid.

[1602] Stream 1542, which may be substantially composed of hydrocarbonswith carbon numbers less than 5, may be injected into formation 678 thatis hot. When the hydrocarbons contact the formation, hydrocarbons maycrack within the formation to produce methane, H₂, coke, and olefinssuch as ethene and propylene. In one embodiment, the production ofolefins may be increased by heating the temperature of the formation tothe upper end of the pyrolysis temperature range and by injectinghydrocarbon fluid at a relatively high rate. Residence time of thehydrocarbons in the formation may be reduced and dehydrogenatedhydrocarbons may form olefins rather than cracking to form H₂ and coke.Olefin production may also be increased by reducing formation pressure.

[1603] In some in situ conversion process embodiments, a hot formationthat was subjected to pyrolysis and/or synthesis gas generation may beused to produce olefins. A hot formation may be significantly lessefficient at producing olefins than a reactor designed to produceolefins. However, a hot formation may have a several orders of magnitudemore surface area and volume than a reactor designed to produce olefins.The reduction in efficiency of a hot formation may be more than offsetby the increased size of the hot formation. A feed stream for olefinproduction in a hot formation may be produced adjacent to the hotformation from a portion of a formation undergoing pyrolysis. Theavailability of a feed stream may also offset efficiency of a hotformation for producing olefins as compared to generating olefins in areactor designed to produce olefins.

[1604] In some in situ conversion process embodiments, H₂ and/ornon-condensable hydrocarbons may be used as a fuel, or as a fuelcomponent, for surface burners or combustors. The combustors may be heatsources used to heat a hydrocarbon containing formation. In some heatsource embodiments, the combustors may be flameless distributedcombustors. In some heat source embodiments, the combustors may benatural distributed combustors and the fuel may be provided to thenatural distributed combustor to supplement the fuel available fromhydrocarbon material in the formation.

[1605] Heater well 520 may heat a portion of a formation to a synthesisgas generating temperature range. Pyrolysis fluid 1542, or a portion ofthe pyrolysis fluid, may be injected into formation 678. In some processembodiments, pyrolysis fluid 1542 introduced into formation 678 mayinclude no, or substantially no, hydrocarbons having carbon numbersgreater than about 4. In other process embodiments, pyrolysis fluid 1542introduced into formation 678 may include a significant portion ofhydrocarbons having carbon numbers greater than 4. In some processembodiments, pyrolysis fluid 1542 introduced into formation 678 mayinclude no, or substantially no, hydrocarbons having carbon numbers lessthan 5. When hydrocarbons in pyrolysis fluid 1542 are introduced intoformation 678, the hydrocarbons may crack within the formation toproduce methane, H₂, and coke.

[1606]FIG. 123 depicts an embodiment of a synthesis gas generatingprocess from hydrocarbon containing formation 678 with flamelessdistributed combustor 1544. Synthesis gas 1502 produced from productionwell 512 may be fed into gas separation unit 1504. Gas separation unit1504 may generate carbon dioxide stream 1506 from other components ofsynthesis gas 1502. First portion 1546 of carbon dioxide may be routedto a formation for sequestration. Second portion 1548 of carbon dioxidemay be injected into the formation with synthesis gas generating fluid.Portion 1550 of stream 1554 from gas separation unit 1504 may beintroduced into heater well 520 as a portion of fuel for combustion inflameless distributed combustor 1544. Flameless distributed combustor1544 may provide heat to the formation. Portion 1552 of stream 1554 maybe fed to fuel cell 1536 for the production of electricity. Electricity1518 may be routed to a power grid. Steam 1392A produced in the fuelcell and steam 1392B produced from combustion in the distributed burnermay be introduced into the formation as a portion of a synthesis gasgeneration fluid.

[1607] In an in situ conversion process embodiment, carbon dioxidegenerated with pyrolysis fluids may be sequestered in a hydrocarboncontaining formation. FIG. 124 illustrates in situ pyrolysis inhydrocarbon containing formation 678. Heat source 508 with electricheater 1132 may be placed in formation 678. Pyrolysis fluids 1484 may beproduced from formation 678 and fed into gas separation unit 1504. Gasseparation unit 1504 may separate pyrolysis fluid 1484 into carbondioxide stream 1506, vapor component 1556, and liquid component 1558.Portion 1560 of carbon dioxide stream 1506 may be stored in formation1562. Formation 1562 may be a coal bed with entrained methane. Thecarbon dioxide may displace some of the methane and allow for productionof methane. The carbon dioxide may be sequestered in spent hydrocarboncontaining formation 1526, injected into oil producing fields 1528 forenhanced oil recovery, or sequestered into coal bed 1564. In someembodiments, portion 1566 of carbon dioxide stream 1506 may bere-injected into a section of formation 678 through a synthesis gasproduction well to promote production of carbon monoxide.

[1608] Vapor component 1556 and/or carbon dioxide stream 1506 may passthrough turbine 1568 or turbines to generate electricity. A portion ofelectricity 1518 generated by the vapor component and/or carbon dioxidemay be used to power electric heaters 1132 placed within formation 678.Initial power and/or make-up power may be provided to electric heatersfrom a power grid.

[1609] As depicted in FIG. 125, heater well 520 may be located withinhydrocarbon containing formation 678. Additional heater wells may alsobe located within formation 678. Heater well 520 may include electricheater 1132 or another type of heat source. Pyrolysis fluid 1484produced from the formation may be fed to reformer 1570 to producesynthesis gas 1502. In some process embodiments, reformer 1570 is asteam reformer. Synthesis gas 1502 may be sent to fuel cell 1536. Aportion of pyrolysis fluid 1484 and/or produced synthesis gas 1502 maybe used as fuel to heat reformer 1570. Reformer 1570 may include acatalyst material that promotes the reforming reaction and a burner tosupply heat for the endothermic reforming reaction. A steam source maybe connected to reformer 1570 to provide steam for the reformingreaction. The burner may operate at temperatures well above thatrequired by the reforming reaction and well above the operatingtemperatures of fuel cells. As such, it may be desirable to operate theburner as a separate unit independent offuel cell 1536.

[1610] In some process embodiments, reformer 1570 may be a tubereformer. Reformer 1570 may include multiple tubes made of refractorymetal alloys. Each tube may include a packed granular or pelletizedmaterial having a reforming catalyst as a surface coating. A diameter ofthe tubes may vary from between about 9 cm and about 16 cm. A heatedlength of each tube may normally be between about 6 m and about 12 m. Acombustion zone may be provided external to the tubes, and may be formedin the burner. A surface temperature of the tubes may be maintained bythe burner at a temperature of about 900° C. to ensure that thehydrocarbon fluid flowing inside the tube is properly catalyzed withsteam at a temperature between about 500° C. and about 700° C. Atraditional tube reformer may rely upon conduction and convection heattransfer within the tube to distribute heat for reforming.

[1611] Pyrolysis fluids 1484 from formation 678 may be pre-processedprior to being fed to reformer 1570. Reformer 1570 may transformpyrolysis fluids 1484 into simpler reactants prior to introduction to afuel cell. For example, pyrolysis fluids 1484 may be pre-processed in adesulfurization unit. Subsequent to pre-processing, pyrolysis fluids1484 may be provided to a reformer and a shift reactor to produce asuitable fuel stock for a H₂ fueled fuel cell.

[1612] Synthesis gas 1502 produced by reformer 1570 may include a numberof components including carbon dioxide, carbon monoxide, methane, and/orhydrogen. Produced synthesis gas 1502 may be fed to fuel cell 1536.Portion 1572 of electricity produced by fuel cell 1536 may be sent to apower grid. In addition, portion 1574 of electricity may be used topower electric heater 1132. Carbon dioxide stream 1506 exiting the fuelcell may be routed to sequestration area 1576. The sequestration areamay be a spent portion of formation 678.

[1613] In a process embodiment, pyrolysis fluid produced from aformation may be fed to the reformer. The reformer may produce a carbondioxide stream and a H₂ stream. For example, the reformer may include aflameless distributed combustor for a core, and a membrane. The membranemay allow only H₂ to pass through the membrane resulting in separationof the H₂ and carbon dioxide. The carbon dioxide may be routed to asequestration area.

[1614] Synthesis gas produced from a formation may be. converted toheavier condensable hydrocarbons. For example, a Fischer-Tropschhydrocarbon synthesis process may be used for conversion of synthesisgas. A Fischer-Tropsch process may include converting synthesis gas tohydrocarbons. The process may use elevated temperatures, normal orelevated pressures, and a catalyst, such as magnetic iron oxide or acobalt catalyst. Products produced from a Fischer-Tropsch process mayinclude hydrocarbons having a broad molecular weight distribution andmay include branched and/or unbranched paraffins. Products from aFischer-Tropsch process may also include considerable quantities ofolefins and oxygen containing organic compounds. An example of aFischer-Tropsch reaction may be illustrated by Reaction 60:

(n+2)CO+(2n+5)H₂

CH₃(—CH₂—)_(n)CH₃+(n+2)H₂O   (60)

[1615] A hydrogen to carbon monoxide ratio for synthesis gas used as afeed gas for a Fischer-Tropsch reaction may be about 2:1. In certainembodiments, the ratio may range from approximately 1.8:1 to 2.2:1.Higher or lower ratios may be accommodated by certain Fischer-Tropschsystems.

[1616]FIG. 126 illustrates a flowchart of a Fischer-Tropsch process thatuses synthesis gas produced from a hydrocarbon containing formation as afeed stream. Hot formation 1578 may be used to produce synthesis gashaving a H₂ to CO ratio of approximately 2:1. The proper ratio may beproduced by operating synthesis production wells at approximately 700°C., or by blending synthesis gas produced from different sections offormation to obtain a synthesis gas having approximately a 2:1 H₂ to COratio. Synthesis gas generating fluid 1498 may be fed into hot formation1578 to generate synthesis gas. H₂ and CO may be separated from thesynthesis gas produced from the hot formation 1578 to form feed stream1580. Feed stream 1580 may be sent to Fischer-Tropsch plant 1582. Feedstream 1580 may supplement or replace synthesis gas 1502 produced fromcatalytic methane reformer 1584.

[1617] Fischer-Tropsch plant 1582 may produce wax feed stream 1586. TheFischer-Tropsch synthesis process that produces wax feed stream 1586 isan exothermic process. Steam 1392 may be generated during theFischer-Tropsch process. Steam 1392 may be used as a portion ofsynthesis gas generating fluid 1498.

[1618] Wax feed stream 1586 produced from Fischer-Tropsch plant 1582 maybe sent to hydrocracker 1588. Hydrocracker 1588 may produce productstream 1590. The product stream may include diesel, jet fuel, and/ornaphtha products. Examples of methods for conversion of synthesis gas tohydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Pat.Nos. 4,096,163 to Chang et al., 6,085,512 to Agee et al., and 6,172,124to Wolflick et al., which are incorporated by reference as if fully setforth herein.

[1619]FIG. 127 depicts an embodiment of in situ synthesis gas productionintegrated with a Shell Middle Distillates Synthesis (SMDS)Fischer-Tropsch and wax cracking process. An example of a SMDS processis illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and isincorporated by reference as if fully set forth herein. A middledistillates hydrocarbon mixture may be produced from produced synthesisgas using the SMDS process as illustrated in FIG. 127. Synthesis gas1502, having a H₂ to carbon monoxide ratio of about 2:1, may exitproduction well 512. The synthesis gas may be fed into SMDS plant 1592.In certain embodiments, the ratio may range from approximately 1.8:1 to2.2:1. Products of the SMDS plant include organic liquid product 1594and steam 1596. Steam 1596 may be supplied to injection wells 606. Steam1596 may be used as a feed for synthesis gas production. Hydrocarbonvapors may in some circumstances be added to the steam.

[1620]FIG. 128 depicts an embodiment of in situ synthesis gas productionintegrated with a catalytic methanation process. Synthesis gas 1502exiting production well 512 may be supplied to catalytic methanationplant 1598. Synthesis gas supplied to catalytic methanation plant 1598may have a H₂ to carbon monoxide ratio of about 3:1. Methane 1600 may beproduced by catalytic methanation plant 1598. Steam 1392 produced byplant 1598 may be supplied to injection well 606 for production ofsynthesis gas. Examples of a catalytic methanation process areillustrated in U.S. Pat. Nos. 3,922,148 to Child; 4,130,575 to Jorn etal.; and 4,133,825 to Stroud et al., which are incorporated by referenceas if fully set forth herein.

[1621] Synthesis gas produced from a formation may be used as a feed fora process for producing methanol. Examples of processes for productionof methanol are described in U.S. Pat. Nos. 4,407,973 to van Dijk etal., 4,927,857 to McShea, III et al., and 4,994,093 to Wetzel et al.,each of which is incorporated by reference as if fully set forth herein.The produced synthesis gas may also be used as a feed gas for a processthat converts synthesis gas to engine fuel (e.g., gasoline or diesel).Examples of processes for producing engine fuels are described in U.S.Pat. Nos. 4,076,761 to Chang et al., 4,138,442 to Chang et al., and4,605,680 to Beuther et al., each of which is incorporated by referenceas if fully set forth herein.

[1622] In a process embodiment, produced synthesis gas may be used as afeed gas for production of ammonia and urea. FIGS. 129 and 130 depictembodiments of making ammonia and urea from synthesis gas. Ammonia maybe synthesized by the Haber-Bosch process, which involves synthesisdirectly from N₂ and H₂ according to Reaction 61:

N₂+3H₂

2NH₃.  (61)

[1623] The N₂ and H₂ may be combined, compressed to high pressure (e.g.,from about 80 bars to about 220 bars), and then heated to a relativelyhigh temperature. The reaction mixture may be passed over a catalystcomposed substantially of iron to produce ammonia. During ammoniasynthesis, the reactants (i.e., N₂ and H₂) and the product (i.e.,ammonia) may be in equilibrium. The total amount of ammonia produced maybe increased by shifting the equilibrium towards product formation.Equilibrium may be shifted to product formation by removing ammonia fromthe reaction mixture as ammonia is produced.

[1624] Removal of the ammonia may be accomplished by cooling the gasmixture to a temperature between about −5° C. to about 25° C. In thistemperature range, a two-phase mixture may be formed with ammonia in theliquid phase and N₂ and H₂ in the gas phase. The ammonia may beseparated from other components of the mixture. The nitrogen andhydrogen may be subsequently reheated to the operating temperature forammonia conversion and passed through the reactor again.

[1625] Urea may be prepared by introducing ammonia and carbon dioxideinto a reactor at a suitable pressure, (e.g., from about 125 barsabsolute to about 350 bars absolute), and at a suitable temperature,(e.g., from about 160° C. to about 250° C.). Ammonium carbamate may beformed according to Reaction 62:

2NH₃+CO₂→NH₂(CO₂)NH₄.  (62)

[1626] Urea may be subsequently formed by dehydrating the ammoniumcarbamate according to equilibrium Reaction 63:

NH₂(CO₂)NH₄

NH₂(CO)NH₂+H₂O.  (63)

[1627] The degree to which the ammonia conversion takes place may dependon the temperature and the amount of excess ammonia. The solutionobtained as the reaction product may include urea, water, ammoniumcarbamate, and unbound ammonia. The ammonium carbamate and the ammoniamay need to be removed from the solution and returned to the reactor.The reactor may include separate zones for the formation of ammoniumcarbamate and urea. However, these zones may also be combined into onepiece of equipment.

[1628] In a process embodiment, a high pressure urea plant may operatesuch that the decomposition of ammonium carbamate that has not beenconverted into urea and the expulsion of the excess ammonia areconducted at a pressure between 15 bars absolute and 100 bars absolute.This pressure may be considerably lower than the pressure in the ureasynthesis reactor. The synthesis reactor may be operated at atemperature of about 180° C. to about 210° C. and at a pressure of about180 bars absolute to about 300 bars absolute. Ammonia and carbon dioxidemay be directly fed to the urea reactor. The NH₃/CO₂ molar ratio (N/Cmolar ratio) in the urea synthesis may generally be between about 3 andabout 5. The unconverted reactants may be recycled to the urea synthesisreactor following expansion, dissociation, and/or condensation.

[1629] In a process embodiment, an ammonia feed stream having a selectedratio of H₂ to N₂ may be generated from a formation using enriched air.A synthesis gas generating fluid and an enriched air stream may beprovided to the formation. The composition of the enriched air may beselected to generate synthesis gas having the selected ratio of H₂ toN₂. In one embodiment, the temperature of the formation may becontrolled to generate synthesis gas having the selected ratio.

[1630] In a process embodiment, the H₂ to N₂ ratio of the feed streamprovided to the ammonia synthesis process may be approximately 3:1. Inother embodiments, the ratio may range from approximately 2.8:1 to3.2:1. An ammonia synthesis feed stream having a selected H₂ to N₂ ratiomay be obtained by blending feed streams produced from differentportions of the formation.

[1631] In a process embodiment, ammonia from the ammonia synthesisprocess may be provided to a urea synthesis process to generate urea.Ammonia produced during pyrolysis may be added to the ammonia generatedfrom the ammonia synthesis process. In another process embodiment,ammonia produced during hydrotreating may be added to the ammoniagenerated from the ammonia synthesis process. Some of the carbonmonoxide in the synthesis gas may be converted to carbon dioxide in ashift process. The carbon dioxide from the shift process may be fed tothe urea synthesis process. Carbon dioxide generated from treatment ofthe formation may also be fed, in some embodiments, to the ureasynthesis process.

[1632]FIG. 129 illustrates an embodiment of a method for production ofammonia and urea from synthesis gas using membrane-enriched air.Enriched air 1602 and steam or water 1604 may be fed into hot carboncontaining formation 1606 to produce synthesis gas 1502 in a wetoxidation mode.

[1633] In some synthesis gas production embodiments, enriched air 1602is blended from air and oxygen streams such that the nitrogen tohydrogen ratio in the produced synthesis gas is about 1:3. The synthesisgas may be at a correct ratio of nitrogen and hydrogen to form ammonia.For example, it has been calculated that for a formation temperature of700° C., a pressure of 3 bars absolute, and with 13,231 tons/day of charthat will be converted into synthesis gas, one could inject 14.7kilotons/day of air, 6.2 kilotons/day of oxygen, and 21.2 kilotons/dayof steam. This would result in production of 2 billion cubic feet/day ofsynthesis gas including 5689 tons/day of steam, 16,778 tons/day ofcarbon monoxide, 1406 tons/day of hydrogen, 18,689 tons/day of carbondioxide, 1258 tons/day of methane, and 11,398 tons/day of nitrogen.After a shift reaction (to shift the carbon monoxide to carbon dioxideand to produce additional hydrogen), the carbon dioxide may be removed,the product stream may be methanated (to remove residual carbonmonoxide), and then one can theoretically produce 13,840 tons/day ofammonia and 1258 tons/day of methane. This calculation includes theproducts produced from Reactions (57) and (58) above.

[1634] Enriched air may be produced from a membrane separation unit.Membrane separation of air may be primarily a physical process. Basedupon specific characteristics of each molecule, such as size andpermeation rate, the molecules in air may be separated to formsubstantially pure forms of nitrogen, oxygen, or combinations thereof.

[1635] In a membrane system embodiment, the membrane system may includea hollow tube filled with a plurality of very thin membrane fibers. Eachmembrane fiber may be another hollow tube in which air flows. The wallsof the membrane fiber may be porous such that oxygen permeates throughthe wall at a faster rate than nitrogen. A nitrogen rich stream may beallowed to flow out the other end of the fiber. Air outside the fiberand in the hollow tube may be oxygen enriched. Such air may be separatedfor subsequent uses, such as production of synthesis gas from aformation.

[1636] In some membrane system embodiments, the purity of nitrogengenerated may be controlled by variation of the flow rate and/orpressure of air through the membrane. Increasing air pressure mayincrease permeation of oxygen molecules through a fiber wall. Decreasingflow rate may increase the residence time of oxygen in the membrane and,thus, may increase permeation through the fiber wall. Air pressure andflow rate may be adjusted to allow a system operator to vary the amountand purity of the nitrogen generated in a relatively short amount oftime.

[1637] The amount of N₂ in the enriched air may be adjusted to provide aN:H ratio of about 3:1 for ammonia production. Synthesis gas may begenerated at a temperature that favors the production of carbon dioxideover carbon monoxide. The temperature during synthesis gas generationmay be maintained between about 400° C. and about 550° C., or betweenabout 400° C. and about 450° C. Synthesis gas produced at such lowtemperatures may include N₂ H₂, and carbon dioxide with little carbonmonoxide.

[1638] As illustrated in FIG. 129, a feed stream for ammonia productionmay be prepared by first feeding synthesis gas stream 1502 into ammoniafeed stream gas processing unit 1608. In ammonia feed stream gasprocessing unit 1608, the feed stream may undergo a shift reaction (toshift the carbon monoxide to carbon dioxide and to produce additionalhydrogen). Carbon dioxide may be removed from the feed stream, and thefeed stream can be methanated (to remove residual carbon monoxide). Incertain embodiments, carbon dioxide may be separated from the feedstream (or any gas stream) by absorption in an amine unit. Membranes orother carbon dioxide separation techniques/equipment may also be used toseparate carbon dioxide from a feed stream.

[1639] Ammonia feed stream 1610 may be fed to ammonia productionfacility 1612 to produce ammonia 1614. Carbon dioxide stream 1506exiting stream gas processing unit 1608 (and/or carbon dioxide fromother sources) may be fed, with ammonia 1614, into urea productionfacility 1616 to produce urea 1618.

[1640] Ammonia and urea may be produced using a carbon containingformation and using an O₂ rich stream and a N₂ rich stream. The O₂ richstream and synthesis gas generating fluid may be provided to aformation. The formation may be heated, or partially heated, byoxidation of carbon in the formation with the O₂ rich stream. H₂ in thesynthesis gas and N₂ from the N₂ rich stream may be provided to anammonia synthesis process to generate ammonia.

[1641]FIG. 130 illustrates a flowchart of an embodiment for productionof ammonia and urea from synthesis gas using cryogenically separatedair. Air 1620 may be fed into cryogenic air separation unit 1622.Cryogenic separation involves a distillation process that may occur attemperatures between about −168° C. and −172° C. In other embodiments,the distillation process may occur at temperatures between about −165°C. and −175° C. Air may liquefy in these temperature ranges. Thedistillation process may be operated at a pressure between about 8 barsabsolute and about 10 bars absolute. High pressures may be achieved bycompressing air and exchanging heat with cold air exiting the column.Nitrogen is more volatile than oxygen and may come off as a distillateproduct.

[1642] N₂ 1624 exiting separator 1622 may be utilized in heat exchangeunit 1626 to condense higher molecular weight hydrocarbons frompyrolysis stream 1628 and to remove lower molecular weight hydrocarbonsfrom the gas phase into a liquid oil phase. Upgraded gas stream 1630containing a higher composition of lower molecular weight hydrocarbonsthan stream 1628 and liquid stream 1632, which includes condensedhydrocarbons, may exit heat exchange unit 1626. N₂ 1624 may also exitheat exchange unit 1626.

[1643] Oxygen 1634 from cryogenic separation unit 1622 and steam 1392,or water, may be fed into hot carbon containing formation 1606 toproduce synthesis gas 1502 in a continuous process. Synthesis gas may begenerated at a temperature that favors the formation of carbon dioxideover carbon monoxide. Synthesis gas 1502 may include H₂ and carbondioxide. Carbon dioxide may be removed from synthesis gas 1502 toprepare a feed stream for ammonia production using amine gas separationunit 1636. H₂ stream 1638 from gas separation unit 1636 and N₂ stream1624 from the heat exchange unit may be fed into ammonia productionfacility 1612 to produce ammonia 1614. Carbon dioxide stream 1506exiting gas separation unit 1636 and ammonia 1614 may be fed into ureaproduction facility 1616 to produce urea 1618.

[1644]FIG. 131 illustrates an embodiment of a method for preparing anitrogen stream for an ammonia and urea process. Air 1620 may beinjected into hot carbon containing formation 1606 to produce carbondioxide by oxidation of carbon in the formation. In an embodiment, aheater may heat at least a portion of the carbon containing formation toa temperature sufficient to support oxidation of the carbon. Thetemperature sufficient to support oxidation may be, for example, about260° C. for coal. Stream 1640 exiting the hot formation may includecarbon dioxide and nitrogen. In some embodiments, a flue gas stream maybe added to stream 1640, or stream 1640 may be a flue gas stream insteadof a stream from a portion of a formation.

[1645] Nitrogen may be separated from carbon dioxide in stream 1640 bypassing the stream through cold spent carbon containing formation 1642.Carbon dioxide may preferentially adsorb versus nitrogen in cold spentformation 1642. For example, at 50° C. and 0.35 bars, the adsorption ofcarbon dioxide on a spent portion of coal may be about 72 m³/metric toncompared to about 15.4 m³/metric ton for nitrogen. Nitrogen 1624 exitingcold spent portion 1642 may be supplied to ammonia production facility1612 with H₂ stream 1638 to produce ammonia 1614. In some processembodiments, H₂ stream 1638 may be obtained from a product streamproduced during synthesis gas generation of a portion of the formation.

[1646]FIG. 132 depicts an embodiment for treating a relatively permeableformation using horizontal heat sources. Heat source 508 may be disposedwithin hydrocarbon layer 522. Hydrocarbon layer 522 may be belowoverburden 524. Overburden 524 may include, but is not limited to,shale, carbonate, and/or other types of sedimentary rock. Overburden 524may have a thickness of about 10 m or more. A thickness of overburden524, however, may vary depending on, for example, a type of formation.Heat source 508 may be disposed substantially horizontally or, in someembodiments, at an angle between horizontal and vertical withinhydrocarbon layer 522. Heat source 508 may provide heat to a portion ofhydrocarbon layer 522.

[1647] Heat source 508 may include a low temperature heat source and/ora high temperature heat source. Provided heat may mobilize a portion ofheavy hydrocarbons within hydrocarbon layer 522. Provided heat may alsopyrolyze a portion of heavy hydrocarbons within hydrocarbon layer 522. Alength of horizontal heat source 508 disposed within hydrocarbon layer522 may be between about 50 m to about 1500 m. The length of heat source508 within hydrocarbon layer 522 may vary, however, depending on, forexample, a width of hydrocarbon layer 522, a desired production rate, anenergy output of heat source 508, and/or a maximum possible length of awellbore and/or heat sources.

[1648]FIG. 133 depicts an embodiment for treating a relatively permeableformation using substantially horizontal heat sources. Heat sources 508may be disposed horizontally within hydrocarbon layer 522. Hydrocarbonlayer 522 may be below overburden 524. Production well 512 may bedisposed vertically, horizontally, or at an angle to hydrocarbon layer522. The location of production well 512 within hydrocarbon layer 522may vary depending on a variety of factors (e.g., a desired productand/or a desired production rate). In certain embodiments, productionwell 512 may be disposed proximate a bottom of hydrocarbon layer 522.Producing proximate the bottom of the relatively permeable formation mayallow for production of a relatively low API gravity fluid. In otherembodiments, production well 512 may be disposed proximate a top ofhydrocarbon layer 522. Producing proximate the top of the relativelypermeable formation may allow for production of a relatively high APIgravity fluid.

[1649] Heat sources 508 may provide heat to mobilize a portion of theheavy hydrocarbons within hydrocarbon layer 522. The mobilized fluidsmay flow towards a bottom of hydrocarbon layer 522 substantially bygravity. The mobilized fluids may be removed through production well512. Each of heat sources 508 disposed at or near the bottom ofhydrocarbon layer 522 may heat some or all of a section proximate thebottom of hydrocarbon layer 522 to a temperature sufficient to pyrolyzeheavy hydrocarbons within the section. Such a section may be referred toas a selected pyrolyzation section. A temperature within the selectedpyrolyzation section may be between about 225° C. and about 400° C.Pyrolysis of the heavy hydrocarbons within the selected pyrolyzationsection may convert a portion of the heavy hydrocarbons intopyrolyzation fluids. The pyrolyzation fluids may be removed throughproduction well 512. Production well 512 may be disposed within theselected pyrolyzation section. In some embodiments, one or more of heatsources 508 may be turned down and/or off after substantially mobilizinga majority of the heavy hydrocarbons within hydrocarbon layer 522. Doingso may more efficiently heat the formation and/or may save input energycosts associated with the in situ process. In addition, the formationmay be heated during off peak times when electricity is cheaper, if theheaters are electric heaters.

[1650] In certain embodiments, heat may be provided within productionwell 512 to vaporize formation fluids. Heat may also be provided withinproduction well 512 to pyrolyze and/or upgrade formation fluids.

[1651] In some embodiments, a pressurizing fluid may be provided intohydrocarbon layer 522 through heat sources 508. The pressurizing fluidmay increase the flow of the mobilized fluids towards production well512. Increasing the pressure of the pressurizing fluid proximate heatsources 508 will tend to increase the flow of the mobilized fluidstowards production well 512. The pressurizing fluid may include, but isnot limited to, steam, N₂, CO₂, CH₄, H₂, combustion products, anon-condensable or condensable component of fluid produced from theformation, by-products of surface processes such as refining orpower/heat generation, and/or mixtures thereof. Alternatively, thepressurizing fluid may be provided through an injection well disposed inthe formation.

[1652] Pressure in the formation may be controlled to control aproduction rate of formation fluids from the formation. The pressure inthe formation may be controlled by adjusting control valves coupled toproduction wells 512, heat sources 508, and/or pressure control wellsdisposed in the formation.

[1653] In an embodiment, an in situ process for treating a relativelypermeable formation may include providing heat to a portion of aformation from a plurality of heat sources. A plurality of heat sourcesmay be arranged within a relatively permeable formation in a pattern.FIG. 134 illustrates an embodiment of pattern 1644 of heat sources 508and production well 512 that may treat a relatively permeable formation.Heat sources 508 may be arranged in a “5 spot” pattern with productionwell 512. In the “5 spot” pattern, four heat sources 508 are arrangedsubstantially around production well 512, as depicted in FIG. 134.Although heat sources 508 are depicted as being equidistant from eachother in FIG. 134, the heat sources may be placed around production well512 and not be equidistant from the production well and/or each other.Depending on the heat generated by each heat source 508, a spacingbetween heat sources 508 and production well 512 may be determined by adesired product or a desired production rate. A spacing between heatsources 508 and production well 512 may be, for example, about 15 m.Heat source 508 may be converted into production well 512. Productionwell 512 may be converted into heat source 508.

[1654]FIG. 135 illustrates an embodiment of pattern 1646 of heat sources508 arranged in a “7 spot” pattern with production well 512. In the “7spot” pattern, six heat sources 508 are arranged substantially aroundproduction well 512, as depicted in FIG. 135. Although heat sources 508are depicted as being equidistant from each other in FIG. 135, the heatsources may be placed around production well 512 and not be equidistantfrom the production well and/or each other. Heat sources 508 may also beused to produce fluids from the formation. In addition, production well512 may be heated.

[1655] In certain embodiments, a pattern of heat sources 508 andproduction wells 512 may vary depending on, for example, the type ofrelatively permeable formation to be treated. A location of productionwell 512 within a pattern of heat sources 508 may be determined by, forexample, a desired heating rate of the relatively permeable formation, aheating rate of the heat sources, a type of heat source, a type ofrelatively permeable formation, a composition of the relativelypermeable formation, a viscosity of fluid in the relatively permeableformation, and/or a desired production rate.

[1656]FIG. 136 illustrates a plan view of an embodiment for treating arelatively permeable formation. Hydrocarbon layer 522 may include heavyhydrocarbons. Production wells 512 may be disposed in hydrocarbon layer522. Hydrocarbon layer 522 may be enclosed between impermeable layers.Underburden 914 may be referred to as base rock. In some embodiments,the overburden and/or the underburden may be somewhat permeable.

[1657] In an embodiment, low temperature heat sources 1648 and hightemperature heat sources 1650 are disposed in production well 512. Lowtemperature heat source 1648 may be a heat source, or heater, thatprovides heat to a selected mobilization section of hydrocarbon layer522, which is substantially adjacent to low temperature heat source1648. The provided heat may heat some or all of the selectedmobilization section to an average temperature within a mobilizationtemperature range of the heavy hydrocarbons contained within hydrocarbonlayer 522. The mobilization temperature range may be between about 50°C. and about 225° C. A selected mobilization temperature may be about100° C. The mobilization temperature may vary, however, depending on aviscosity of the heavy hydrocarbons contained within hydrocarbon layer522. For example, a higher mobilization temperature may be required tomobilize a higher viscosity fluid within hydrocarbon layer 522.

[1658] High temperature heat source 1650 may be a heat source, orheater, that provides heat to selected pyrolyzation section 1652 ofhydrocarbon layer 522, which may be substantially adjacent to the hightemperature heat source. The provided heat may heat some or all ofselected pyrolyzation section 1652 to an average temperature within apyrolyzation temperature range of the heavy hydrocarbons containedwithin hydrocarbon layer 522. The pyrolyzation temperature range may bebetween about 225° C. and about 400° C. A selected pyrolyzationtemperature may be about 300° C. The pyrolyzation temperature may vary,however, depending on formation characteristics, composition, pressure,and/or a desired quality of a product produced from the formation. Aquality of the product may be determined based upon properties of theproduct (e.g., the API gravity of the product). Pyrolyzation may includecracking of the heavy hydrocarbons into hydrocarbon fragments and/orlighter hydrocarbons. Pyrolyzation of the heavy hydrocarbons tends toupgrade the quality of the heavy hydrocarbons.

[1659] As shown in FIG. 136, mobilized fluids in hydrocarbon layer 522may flow into selected pyrolyzation section 1652 substantially bygravity. The mobilized fluids may be upgraded by pyrolysis in selectedpyrolyzation section 1652. Flow of the mobilized fluids may optionallybe increased by providing pressurizing fluid 1654 (e.g., through conduit1656 or any injection well placed in the formation) into the formation.Pressurizing fluid 1654 may be a fluid that increases a pressure in theformation proximate conduit 1656. The increased pressure proximateconduit 1656 may increase flow of the mobilized fluids in hydrocarbonlayer 522 into selected pyrolyzation section 1652. A pressure ofpressurizing fluid 1654 provided by conduit 1656 may be between, in oneembodiment, about 7 bars absolute to about 70 bars absolute. Thepressure of pressurizing fluid 1654 may vary, depending on, for example,a viscosity of fluid within hydrocarbon layer 522, the depth ofoverburden 524, and/or a desired flow rate of fluid into selectedpyrolyzation section 1652. Pressurizing fluid 1654 may, in certainembodiments, be any gas that does not result in significant oxidation ofthe heavy hydrocarbons. For example, pressurizing fluid 1654 may includesteam, N₂, CO₂, CH₄, hydrogen, etc.

[1660] Production wells 512 may remove pyrolyzation fluids and/ormobilized fluids from selected pyrolyzation section 1652. In someembodiments, formation fluids may be removed as vapor. The formationfluids may be upgraded by reactions induced by high temperature heatsource 1650 and/or low temperature heat source 1648 in production well512. Production well 512 may control pressure in selected pyrolyzationsection 1652 to provide a pressure gradient so that mobilized fluidsflow into selected pyrolyzation section 1652 from the selectedmobilization section. In some embodiments, pressure in selectedpyrolyzation section 1652 may be controlled to control the flow of themobilized fluids into selected pyrolyzation section 1652. By not heatingthe entire formation to pyrolyzation temperatures, the drainage processmay produce a higher ratio of energy produced versus energy input forthe in situ conversion process (as compared to heating the entireformation to pyrolysis temperatures).

[1661] In addition, pressure in the formation may be controlled toproduce a desired quality of formation fluids. For example, the pressurein the formation may be increased to produce formation fluids with anincreased API gravity as compared to formation fluids produced at alower pressure. Increasing the pressure in the formation may increase ahydrogen partial pressure in mobilized and/or pyrolyzation fluids. Theincreased hydrogen partial pressure in mobilized and/or pyrolyzationfluids may reduce the heavy hydrocarbons in mobilized and/orpyrolyzation fluids. Reducing the heavy hydrocarbons may producelighter, more valuable hydrocarbons. An API gravity of the hydrogenatedheavy hydrocarbons may be higher than an API gravity of theun-hydrogenated heavy hydrocarbons.

[1662] In an embodiment, pressurizing fluid 1654 may be provided to theformation through a conduit disposed in/or proximate production well512. The conduit may provide pressurizing fluid 1654 into hydrocarbonlayer 522 proximate overburden 524. In some embodiments, the conduit isan injection well.

[1663] In another embodiment, low temperature heat source 1648 may beturned down and/or off in production wells 512. The heavy hydrocarbonsin hydrocarbon layer 522 may be mobilized by transfer of heat fromselected pyrolyzation section 1652 into an adjacent portion ofhydrocarbon layer 522. Heat transfer from selected pyrolyzation section1652 may be substantially by conduction.

[1664]FIG. 137 illustrates an embodiment for treating a relativelypermeable formation without substantially pyrolyzing mobilized fluids.Low temperature heat source 1648 may be placed in production well 512.Low temperature heat source 1648 may provide heat to hydrocarbon layer522 to heat some or all of hydrocarbon layer 522 to an averagetemperature within the mobilization temperature range. Mobilized fluidswithin hydrocarbon layer 522 may flow towards a bottom of hydrocarbonlayer 522 substantially by gravity. Pressurizing fluid 1654 may beprovided into the formation through conduit 1656 and may increase a flowof the mobilized fluids towards the bottom of hydrocarbon layer 522.Pressurizing fluid 1654 may also be provided into the formation throughanother conduit, such as a conduit disposed in/or proximate productionwell 512. Formation fluids may be removed through production well 512 atand/or near the bottom of hydrocarbon layer 522. Low temperature heatsource 1648 may provide heat to the formation fluids removed throughproduction well 512. The provided heat may vaporize the removedformation fluids within production well 512 such that the formationfluids may be removed as a vapor. The provided heat may also increase anAPI gravity of the removed formation fluids within production well 512.

[1665]FIG. 138 illustrates an embodiment for treating a relativelypermeable formation with layers 1658 of heavy hydrocarbons separated bylayers 1660. Such layers 1660 may, for example, be impermeable layers orless permeable layers of the formation. Heater well 520 and productionwell 512 may be disposed in the relatively permeable formation. Layers1660 may separate layers 1658. Heavy hydrocarbons may be disposed inlayers 1658. Low temperature heat source 1648 may be disposed ininjection well 520. Heavy hydrocarbons may be mobilized by heat providedfrom low temperature heat source 1648 such that a viscosity of the heavyhydrocarbons is substantially reduced. Pressurizing fluid 1654 may beprovided through openings in injection well 520 into layers 1658. Thepressure of pressurizing fluid 1654 may cause the mobilized fluids toflow towards production well 512. The pressure of pressurizing fluid1654 at or near injection well 520 may be, for example, about 7 barsabsolute to about 70 bars absolute. The pressure of pressurizing fluid1654 is, however, generally controlled to remain below a pressure thatcan lift the overburden.

[1666] High temperature heat source 1650 may, in some embodiments, bedisposed in production well 512. Heat provided by high temperature heatsource 1650 may pyrolyze a portion of the mobilized fluids within aselected pyrolyzation section proximate production well 512. Thepyrolyzation and/or mobilized fluids may be removed from layers 1658 byproduction well 512. High temperature heat source 1650 may causereactions that further upgrade the removed formation fluids withinproduction well 512. In some embodiments, the removed formation fluidsmay be removed as vapor through production well 512. A pressure at ornear production well 512 may be less than about 70 bars absolute. Notheating the entire formation to pyrolyzation temperatures may produce ahigher ratio of energy produced versus energy input for the in situconversion process as compared to heating the entire formation topyrolysis temperatures. Upgrading of the formation fluids at or nearproduction well 512 may produce a higher value product.

[1667] In another embodiment, high temperature heat source 1650 may besupplemented or replaced with low temperature heat source 1648 withinproduction well 512. Low temperature heat source 1648 may produce lesspyrolyzation of the heavy hydrocarbons within layers 1658 than hightemperature heat source 1650. Therefore, the formation fluids removedthrough production well 512 produced with low temperature heat source1648 may not be as upgraded as formation fluids removed throughproduction well 512 produced with high temperature heat source 1650.

[1668] In another embodiment, pyrolyzation of the heavy hydrocarbons maybe increased by replacing low temperature heat source 1648 with hightemperature heat source 1650 within injection well 520. High temperatureheat source 1650 may allow for more pyrolyzation of the heavyhydrocarbons within layers 1658 than low temperature heat source 1648.The formation fluids removed through production well 512 may be higherin value as compared to the formation fluids removed in a process usinglow temperature heat source 1648 within injection well 520 as describedin the embodiment shown in FIG. 138.

[1669] In some embodiments, a relatively permeable formation may bebelow a thick impermeable layer (overburden). The overburden may have athickness ranging from about 10 m to about 300 m or more. The overburdenmay inhibit vapor release to the atmosphere.

[1670] In some embodiments, portions of heat sources may be placedhorizontally or non-vertically in a relatively permeable formation.Using horizontal or directionally drilled heat sources may be moreeconomical than using vertical or substantially vertical heat sources.Portions of production wells may also be disposed horizontally ornon-vertically within the relatively permeable formation.

[1671] In an embodiment, production of hydrocarbons from a formation isinhibited until at least some hydrocarbons within the formation havebeen pyrolyzed. A mixture may be produced from the formation at a timewhen the mixture includes a selected quality in the mixture (e.g., APIgravity, hydrogen concentration, aromatic content, etc.). In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increase conversion of heavy hydrocarbonsto light hydrocarbons. Inhibiting initial production may minimize theproduction of heavy hydrocarbons from the formation. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

[1672] In one embodiment, the time for beginning production may bedetermined by sampling a test stream produced from the formation. Thetest stream may be an amount of fluid produced through a production wellor a test well. The test stream may be a portion of fluid removed fromthe formation to control pressure within the formation. The test streammay be tested to determine if the test stream has a selected quality.For example, the selected quality may be a selected minimum API gravityor a selected maximum weight percentage of heavy hydrocarbons. When thetest stream has the selected quality, production of the mixture may bestarted through production wells and/or heat sources in the formation.

[1673] In an embodiment, the time for beginning production is determinedfrom laboratory experimental treatment of samples obtained from theformation. For example, a laboratory treatment may include a pyrolysisexperiment used to determine a process time that produces a selectedminimum API gravity from the sample.

[1674] In one embodiment, measuring a pressure (e.g., a downholepressure in a production well) is used to determine the time forbeginning production from a formation. For example, production may bestarted when a minimum selected downhole pressure is reached in aproduction well in a selected section of the formation.

[1675] In an embodiment, the time for beginning production is determinedfrom a simulation for treating the formation. The simulation may be acomputer simulation that simulates formation conditions (e.g., pressure,temperature, production rates, etc.) to determine qualities of fluidsproduced from the formation.

[1676] When production of hydrocarbons from the formation is inhibited,the pressure in the formation tends to increase with temperature in theformation because of thermal expansion and/or phase change of heavyhydrocarbons and other fluids (e.g., water) in the formation. Pressurewithin the formation may have to be maintained below a selected pressureto inhibit unwanted production, fracturing of the overburden orunderburden, and/or coking of hydrocarbons in the formation. Theselected pressure may be a lithostatic or hydrostatic pressure of theformation. For example, the selected pressure may be about 150 barsabsolute or, in some embodiments, the selected pressure may be about 35bars absolute. The pressure in the formation may be controlled bycontrolling production rate from production wells in the formation. Inother embodiments, the pressure in the formation is controlled byreleasing pressure through one or more pressure relief wells in theformation. Pressure relief wells may be heat sources or separate wellsinserted into the formation. Formation fluid removed from the formationthrough the relief wells may be sent to a treatment facility. Producingat least some hydrocarbons from the formation may inhibit the pressurein the formation from rising above the selected pressure.

[1677] In certain embodiments, some formation fluids may be backproduced through a heat source wellbore. For example, some formationfluids may be back produced through a heat source wellbore during earlytimes of heating of a hydrocarbon containing formation. In anembodiment, some formation fluids may be produced through a portion of aheat source wellbore. Injection of heat may be adjusted along the lengthof the wellbore so that fluids produced through the wellbore are notoverheated. Fluids may be produced through portions of the heat sourcewellbore that are at lower temperatures than other portions of thewellbore.

[1678] Producing at least some formation fluids through a heat sourcewellbore may reduce or eliminate the need for additional productionwells in a formation. In addition, pressures within the formation may bereduced by producing fluids through a heat source wellbore (especiallywithin the region surrounding the heat source wellbore). Reducingpressures in the formation may alter the ratio of produced liquids toproduced vapors. In certain embodiments, producing fluids through theheat source wellbore may lead to earlier production of fluids from theformation. Portions of the formation closest to the heat source wellborewill increase to mobilization and/or pyrolysis temperatures earlier thanportions of the formation near production wells. Thus, fluids may beproduced at earlier times from portions near the heat source wellbore.

[1679]FIG. 139 depicts an embodiment of a heater well for selectivelyheating a formation. Heat source 508 may be placed in opening 544 inhydrocarbon layer 522. In certain embodiments, opening 544 may be asubstantially horizontal opening within hydrocarbon layer 522.Perforated casing 1254 may be placed in opening 544. Perforated casing1254 may provide support from hydrocarbon and/or other material inhydrocarbon layer 522 collapsing opening 544. Perforations in perforatedcasing 1254 may allow for fluid flow from hydrocarbon layer 522 intoopening 544. Heat source 508 may include hot portion 1662. Hot portion1662 may be a portion of heat source 508 that operates at higher heatoutputs of a heat source. For example, hot portion 1662 may outputbetween about 650 watts per meter and about 1650 watts per meter. Hotportion 1662 may extend from a “heel” of the heat source to the end ofthe heat source (i.e., the “toe” of the heat source). The heel of a heatsource is the portion of the heat source closest to the point at whichthe heat source enters a hydrocarbon layer. The toe of a heat source isthe end of the heat source furthest from the entry of the heat sourceinto a hydrocarbon layer.

[1680] In an embodiment, heat source 508 may include warm portion 1664.Warm portion 1664 may be a portion of heat source 508 that operates atlower heat outputs than hot portion 1662. For example, warm portion 1664may output between about 150 watts per meter and about 650 watts permeter. Warm portion 1664 may be located closer to the heel of heatsource 508. In certain embodiments, warm portion 1664 may be atransition portion (i.e., a transition conductor) between hot portion1662 and overburden portion 1666. Overburden portion 1666 may be locatedwithin overburden 524. Overburden portion 1666 may provide a lower heatoutput than warm portion 1664. For example, overburden portion mayoutput between about 30 watts per meter and about 90 watts per meter. Insome embodiments, overburden portion 1666 may provide as close to noheat (0 watts per meter) as possible to overburden 524. Some heat,however, may be used to maintain fluids produced through opening 544 ina vapor phase within overburden 524.

[1681] In certain embodiments, hot portion 1662 of heat source 508 mayheat hydrocarbons to high enough temperatures to result in coke 1668forming in hydrocarbon layer 522. Coke 1668 may occur in an areasurrounding opening 544. Warm portion 1664 may be operated at lower heatoutputs such that coke does not form at or near the warm portion of heatsource 508. Coke 1668 may extend radially from opening 544 as heat fromheat source 508 transfers outward from the opening. At a certaindistance, however, coke 1668 no longer forms because temperatures inhydrocarbon layer 522 at the certain distance will not reach cokingtemperatures. The distance at which no coke forms may be a function ofheat output (watts per meter from heat source 508), type of formation,hydrocarbon content in the formation, and/or other conditions within theformation.

[1682] The formation of coke 1668 may inhibit fluid flow into opening544 through the coking. Fluids in the formation may, however, beproduced through opening 544 at the heel of heat source 508 (i.e., atwarm portion 1664 of the heat source) where there is no coke formation.The lower temperatures at the heel of heat source 508 may reduce thepossibility of increased cracking of formation fluids produced throughthe heel. Fluids may flow in a horizontal direction through theformation more easily than in a vertical direction. Typically,horizontal permeability in a relatively permeable formation (e.g., a tarsands formation) is about 5 to 10 times greater than verticalpermeability. Thus, fluids may flow along the length of heat source 508in a substantially horizontal direction. Producing formation fluidsthrough opening 544 may be possible at earlier times than producingfluids through production wells in hydrocarbon layer 522. The earlierproduction times through opening 544 may be possible becausetemperatures near the opening increase faster than temperatures furtheraway due to conduction of heat from heat source 508 through hydrocarbonlayer 522. Early production of formation fluids may be used to maintainlower pressures in hydrocarbon layer 522 during start-up heating of theformation (i.e., before production begins at production wells in theformation). Lower pressures in the formation may increase liquidproduction from the formation. In addition, producing formation fluidsthrough opening 544 may reduce the number of production wells needed inthe formation.

[1683] Alternately, in certain embodiments portions of a heater may bemoved or removed, thereby shortening the heated section. For example, ina horizontal well the heater may initially extend to the “toe.” Asproducts are produced from the formation, the heater may be moved sothat it is placed at location further from the “toe.” Heat may beapplied to a different portion of the formation.

[1684] In an embodiment for treating a relatively permeable formation,mobilized fluids may be produced from the formation with limited or nopyrolyzing and/or upgrading of the mobilized fluids. The produced fluidsmay be further treated in a treatment facility located near theformation or at a remotely located treatment facility. The producedfluids may be treated such that the fluids can be transported (e.g., bypipeline, ship, etc.). Heat sources in such an embodiment may have alarger spacing than may be needed for producing pyrolyzed formationfluids. For example, a spacing between heat sources may be about 15 m,about 30 m, or even about 40 m for producing substantially un-pyrolyzedfluids from a relatively permeable formation. An average temperature ofthe formation may be between about 50° C. and about 225° C., or, in someembodiments, between about 150° C. and about 200° C. or between about100° C. and about 150° C. For example, a well spacing of about 30 m mayproduce an average temperature in the formation of about 150° C. inabout ten years, assuming a constant heat output from the heat sources.Smaller heat source spacings may be used to increase a temperature risewithin the formation. For example, a well spacing of about 15 m willtend to produce an average temperature in the formation of about 150° C.in less than about a year. Larger well spacings may decrease costsassociated with, but not limited to, forming wellbores, purchasing andinstalling heating equipment, and providing energy to heat theformation.

[1685] In certain embodiments, the average temperature of a relativelypermeable formation is kept below the boiling point of water atformation conditions (e.g., formation pressure) in order to limit theenthalpy of vaporization loss to boiling the water. Production wells mayalso be operated to minimize the production of steam from the formation.

[1686] In some embodiments, the ratio of energy output of the formationto energy input into the formation may be increased by producing alarger percentage of heavy hydrocarbons versus light hydrocarbons fromthe formation. The energy content of heavy hydrocarbons tends to behigher than the energy content of light hydrocarbons. Producing moreheavy hydrocarbons may increase the ratio of energy output to energyinput. In addition, production costs (such as heat input) for heavyhydrocarbons from a relatively permeable formation may be less thanproduction costs for light hydrocarbons. In certain embodiments, theenergy output to energy input ratio is at least about 5. In otherembodiments, the energy output to energy input ratio is at least about 6or at least about 7. In general, energy output to energy input ratiosfor in situ production from a relatively permeable formation may beimproved versus typical production techniques. For example, steamproduction of heavy hydrocarbons typically have energy ratios betweenabout 2.7 and about 3.3. Steam production may also produce about 28% toabout 40% of the initial hydrocarbons in place from the formation. Insitu production from a relatively permeable formation may produce, incertain embodiments, greater than about 50% of the initial hydrocarbonsin place.

[1687] “Hot zones” (or “hot sections”) may be created in a formation toallow for production of hydrocarbons from the formation. Hydrocarbonfluids that are originally in the hot zones may be produced at atemperature that mobilizes the fluids within the hot zones. Removingfluids from the hot zone may create a pressure or flow gradient thatallows mobilized fluids from other zones (or sections) of the formationto flow into the hot zones when the other zones are heated tomobilization temperatures. The one or more hot zones may be heated to atemperature for pyrolyzation of hydrocarbons that flow into the hotzones. Temperatures in other zones of the formation may only be highenough such that fluids within the other zones are mobilized and flowinto the hot zones. Maintaining lower temperatures within these otherzones may reduce energy costs associated with heating a relativelypermeable formation compared to heating the entire formation (includinghot zones and other zones) to pyrolyzation temperatures. In addition,producing fluids from the one or more hot zones rather than throughoutthe formation reduces costs associated with installation and operationof production wells.

[1688]FIG. 140 depicts a cross-sectional representation of an embodimentfor treating a formation containing heavy hydrocarbons with multipleheating sections. Heat sources 508 may be placed within first section1670. Heat sources 508 may be placed in a desired pattern, (e.g.,hexagonal, triangular, square, etc.). In an embodiment, heat sources 508are placed in triangular patterns. A spacing between heat sources 508may be less than about 25 m within first section 1670 or, in someembodiments, less about 20 m or less than about 15 m. A volume of firstsection 1670 (as well as second sections 1672 and third sections 1674)may be determined by a pattern and spacing of heat sources 508 withinthe section and/or a heat output of the heat sources. Production wells512 may be placed within first section 1670. A number, orientation,and/or location of production wells 512 may be determined byconsiderations including, but not limited to, a desired production rate,a selected product quality, and/or a ratio of heavy hydrocarbons tolight hydrocarbons. For example, one production well 512 may be placedin an upper portion of first section 1670. In some embodiments, aninjection well 606 is placed in first section 1670. Injection well 606(and/or a heat source or production well) may be used to provide apressurizing fluid into first section 1670. The pressurizing fluid mayinclude, but is not limited to, steam, carbon dioxide, N₂, CH₄,combustion products, non-condensable and condensable fluid produced fromthe formation, or combinations thereof. In certain embodiments, alocation of injection well 606 is chosen such that the recovery offluids from first section 1670 is increased with the providedpressurizing fluid.

[1689] In an embodiment, heat sources 508 are used to provide heat tofirst section 1670. First section 1670 may be heated such that at leastsome heavy hydrocarbons within the first section are mobilized. Atemperature at which at least some hydrocarbons are mobilized (i.e., amobilization temperature) may be between about 50° C. and about 210° C.In other embodiments, a mobilization temperature is between about 50° C.and about 150° C. or between about 50° C. and about 100° C.

[1690] In an embodiment, a first mixture is produced from first section1670. The first mixture may be produced through production well 512 orproduction wells and/or heat sources 508. The first mixture may includemobilized fluids from the first section. The mobilized fluids mayinclude at least some hydrocarbons from first section 1670. In certainembodiments, the mobilized fluids produced include heavy hydrocarbons.An API gravity of the first mixture may be less than about 20°, lessthan about 15°, or less than about 10°. In some embodiments, the firstmixture includes at least some pyrolyzed hydrocarbons. Some hydrocarbonsmay be pyrolyzed in portions of first section 1670 that are at highertemperatures than a remainder of the first section. For example,portions adjacent heat sources 508 may be at somewhat highertemperatures (e.g., approximately 50° C. to approximately 100° C.higher) than the remainder of first section 1670.

[1691] Second sections 1672 may be adjacent to first section 1670.Second sections 1672 may include heat sources 508. Heat sources 508 insecond section 1672 may be arranged in a pattern similar to a pattern ofheat sources 508 in first section 1670. In some embodiments, heatsources 508 in second section 1672 are arranged in a different patternthan heat sources 508 in first section 1670 to provide desired heatingof the second section. In certain embodiments, a spacing between heatsources 508 in second section 1672 is greater than a spacing betweenheat sources 508 in first section 1670. Heat sources 508 may provideheat to second section 1672 to mobilize at least some hydrocarbonswithin the second section.

[1692] In an embodiment, temperature within first section 1670 may beincreased to a pyrolyzation temperature after production of the firstmixture. A pyrolyzation temperature in the first section may be betweenabout 225° C. and about 375° C. In some instances, a pyrolyzationtemperature in the first section may be at least about 250° C., or atleast about 275° C. Mobilized fluids (e.g., mobilized heavyhydrocarbons) from second section 1672 may be allowed to flow into firstsection 1670. Some of the mobilized fluids from second section 1672 thatflow into first section 1670 may be pyrolyzed within the first section.Pyrolyzing the mobilized fluids in first section 1670 may upgrade aquality of fluids (e.g., increase an API gravity of the fluid).

[1693] In certain embodiments, a second mixture is produced from firstsection 1670. The second mixture may be produced through production well512 or production wells and/or heat sources 508. The second mixture mayinclude at least some hydrocarbons pyrolyzed within first section 1670.Mobilized fluids from second section 1672 and/or hydrocarbons originallywithin first section 1670 may be pyrolyzed within the first section.Conversion of heavy hydrocarbons to light hydrocarbons by pyrolysis maybe controlled by controlling heat provided to first section 1670 andsecond section 1672. In some embodiments, the heat provided to firstsection 1670 and second section 1672 is controlled by adjusting the heatoutput of a heat source or heat sources 508 within the first section. Inother embodiments, the heat provided to first section 1670 and secondsection 1672 is controlled by adjusting the heat output of a heat sourceor heat sources 508 within the second section. The heat output of heatsources 508 within first section 1670 and second section 1672 may beadjusted to control the heat distribution within hydrocarbon layer 522to account for the flow of fluids along a vertical and/or horizontalplane within the formation. For example, the heat output may be adjustedto balance heat and mass fluxes within the formation so that mass withinthe formation (e.g., fluids within the formation) is substantiallyuniformly heated.

[1694] Producing fluid from production wells in the first section maylower the average pressure in the formation by forming an expansionvolume for fluids heated in adjacent sections of the formation. Thus,producing fluid from production wells in the first section may establisha pressure gradient in the formation that draws mobilized fluid fromadjacent sections into the first section. In some embodiments, apressurizing fluid is provided in second section 1672 (e.g., throughinjection well 606) to increase mobilization of hydrocarbons within thesecond section. The pressurizing fluid may enhance the pressure gradientin the formation to flow mobilized hydrocarbons into first section 1670.In certain embodiments, the production of fluids from first section 1670allows the pressure in second section 1672 to remain below a selectedpressure (e.g., a pressure below which fracturing of the overburden mayoccur).

[1695] In some embodiments, a pressurizing fluid is provided into secondsection 1672 (e.g., through injection well 606) to increase mobilizationof hydrocarbons within the second section. The pressurizing fluid mayalso be used to increase a flow of mobilized hydrocarbons into firstsection 1670. For example, a pressure gradient may be produced betweensecond section 1672 and first section 1670 such that the flow of fluidsfrom the second section to the first section is increased.

[1696] Third sections 1674 may be adjacent to second sections 1672. Heatmay be provided to third section 1674 from heat sources 508. Heatsources 508 in third section 1674 may be arranged in a pattern similarto a pattern of heat sources 508 in first section 1670 and/or heatsources in the second section 1672. In some embodiments, heat sources508 in third section 1674 are arranged in a different pattern than heatsources 508 in first section 1670 and/or heat sources in the secondsection 1672. In certain embodiments, a spacing between heat sources 508in third section 1674 is greater than a spacing between heat sources 508in first section 1670. Heat sources 508 may provide heat to thirdsection 1674 to mobilize at least some hydrocarbons within the thirdsection.

[1697] In an embodiment, a temperature within second section 1672 may beincreased to a pyrolyzation temperature after production of the firstmixture. Mobilized fluids from third section 1674 may be allowed to flowinto second section 1672. Some of the mobilized fluids from thirdsection 1674 that flow into second section 1672 may be pyrolyzed withinthe second section. A mixture may be produced from second section 1672.The mixture produced from second section 1672 may include at least somepyrolyzed hydrocarbons. An API gravity of the mixture produced fromsecond section 1672 may be at least about 200, 30°, or 40°. The mixturemay be produced through production wells 512 and/or heat sources 508placed in second section 1672. Heat provided to third section 1674 andsecond section 1672 may be controlled to control conversion of heavyhydrocarbons to light hydrocarbons and/or a desired characteristic ofthe mixture produced in the second section.

[1698] In another embodiment, mobilized fluids from third section 1674are allowed to flow through second section 1672 and into first section1670. At least some of the mobilized fluids from third section 1674 maybe pyrolyzed in first section 1670. In addition, some of the mobilizedfluids from third section 1674 may be produced as a portion of thesecond mixture in first section 1670. The heavy hydrocarbon fraction inproduced fluids may decrease as successive sections of the formation areproduced through first section 1670.

[1699] In some embodiments, a pressurizing fluid is provided in thirdsection 1674 (e.g., through injection well 606) to increase mobilizationof hydrocarbons within the third section. The pressurizing fluid mayalso be used to increase a flow of mobilized hydrocarbons into secondsection 1672 and/or first section 1670. For example, a pressure gradientmay be produced between third section 1674 and first section 1670 suchthat the flow of fluids from the third section towards the first sectionis increased.

[1700] In an embodiment, heat provided to second section 1672, thirdsection 1674, and any subsequent sections may be turned onsimultaneously after first section 1670 has been substantially depletedof hydrocarbons and other fluids (e.g., brine). The delay betweenproviding heat to first section 1670 and subsequent sections (e.g.,second section 1672, third section 1674, etc.) may be, for example,about 1 year, about 1.5 years, or about 2 years.

[1701] Hydrocarbons may be produced from first section 1670 and/orsecond section 1672 such that at least about 50% by weight of theinitial mass of hydrocarbons in the formation are produced. In otherembodiments, at least about 60% by weight or at least about 70% byweight of the initial mass of hydrocarbons in the formation areproduced.

[1702] In certain embodiments, hydrocarbons may be produced from theformation such that at least about 60% by volume of the initial volumein place of hydrocarbons is produced from the formation. In someembodiments, at least about 70% by volume of the initial volume in placeof hydrocarbons or at least about 80% by volume of the initial volume inplace of hydrocarbons may be produced from the formation.

[1703]FIG. 141 depicts a schematic of an embodiment for treating arelatively permeable formation using a combination of production andheater wells in the formation. Heat sources 508A and 508B may be placedsubstantially horizontally within hydrocarbon layer 522. Heat sources508A may be placed in upper portion 1676 of hydrocarbon layer 522. Heatsources 508B may be placed in lower portion 1678 of hydrocarbon layer522. In some embodiments, heat sources 508A, 508B or selected heatsources may be used as fluid injection wells. Heat sources 508A and/orheat sources 508B may be placed in a triangular pattern withinhydrocarbon layer 522. A pattern of heat sources within hydrocarbonlayer 522 may be repeated as needed depending on various factors (e.g.,a width of the formation, a desired heating rate, and/or a desiredproduction rate).

[1704] Other patterns of heat sources, such as squares, rectangles,hexagons, octagons, etc., may be used within the formation. In someembodiments, heat sources 508B may be placed proximate a bottom ofhydrocarbon layer 522. Heat sources 508B may be placed from about 1 m toabout 6 m from the bottom of the formation, from about 1 m to about 4 mfrom the bottom of the formation, or possibly from about 1 m to about 2m from the bottom of the formation. In certain embodiments, heat inputvaries between heat sources 508A and heat sources 508B. The differencein heat input may reduce costs and/or allow for production of a desiredproduct. For example, heat sources 508A in an upper portion of theformation may be turned down and/or off after some fluids withinhydrocarbon layer 522 have been mobilized. Turning off or reducing heatoutput of a heater may inhibit excessive cracking of hydrocarbon vaporsbefore the vapors are produced from the formation. Turning off orreducing heat output of a heater or heaters may reduce energy costs forheating the formation.

[1705]FIG. 142 depicts a schematic of the embodiment of FIG. 141. Heatsources 508A and 508B may be placed substantially horizontally withinhydrocarbon layer 522. Heat sources 508A and 508B may enter hydrocarbonlayer 522 through one or more vertical or slanted wellbores formedthrough an overburden of the formation. In some embodiments, each heatsource may have its own wellbore. In other embodiments, one or more heatsources may branch from a common wellbore. In another embodiment, one ormore heat sources are placed in the formation as shown in FIGS. 7 and 8.

[1706] Formation fluids may be produced through production wells 512, asshown in FIGS. 141 and 142. In certain embodiments, production wells 512are placed in upper portion 1676 of hydrocarbon layer 522. Productionwell 512 may be placed proximate overburden 524. For example, productionwell 512 may be placed about 1 m to about 20 m from overburden 524,about 1 m to about 4 m from the overburden, or possibly about 1 m toabout 3 m from the overburden. In some embodiments, at least someformation fluids are produced through heat sources 508A, 508B orselected heat sources.

[1707] In some embodiments, a pressurizing fluid (e.g., a gas) isprovided to a relatively permeable formation to increase mobility ofhydrocarbons within the formation. Providing a pressurizing fluid mayincrease a shear rate applied to hydrocarbon fluids in the formation anddecrease the viscosity of hydrocarbon fluids within the formation. Insome embodiments, pressurizing fluid is provided to the selected sectionbefore significant heating of the formation. Pressurizing fluidinjection may increase a portion of the formation available forproduction. Pressurizing fluid injection may increase a ratio of energyoutput of the formation (i.e., energy content of products produced fromthe formation) to energy input into the formation (i.e., energy costsfor treating the formation).

[1708] As shown in FIG. 141, injection well 606 may be placed in theformation to introduce the pressurizing fluid into the formation.Injection well 606 may, in certain embodiments, be placed between twoheat sources 508A, 508B. However, a location of an injection well may bevaried. In certain embodiments, a pressurizing fluid is injected througha heat source or production well placed in a relatively permeableformation. In some embodiments, more than one injection well 606 isplaced in the formation. The pressurizing fluid may include gases suchas carbon dioxide, N₂, steam, CH₄, and/or mixtures thereof. In someembodiments, fluids produced from the formation (e.g., combustion gases,heater exhaust gases, or produced formation fluids) may be used aspressurizing fluid. Providing the pressurizing fluid may increase apressure in a selected section of the formation. The pressure in theselected section may be maintained below a selected pressure. Forexample, the pressure may be maintained below about 150 bars absolute,about 100 bars absolute, or about 50 bars absolute. In some embodiments,the pressure may be maintained below about 35 bars absolute. Pressuremay be varied depending on a number of factors (e.g., desired productionrate or an initial viscosity of tar in the formation). Injection of agas into the formation may result in a viscosity reduction of some ofthe tar in the formation.

[1709] In some embodiments, pressure is maintained by controlling flow(e.g., injection rate) of the pressurizing fluid into the selectedsection. In other embodiments, the pressure is controlled by varying alocation for injecting the pressurizing fluid. In other embodiments,pressure is maintained by controlling a pressure and/or production rateat production wells 512.

[1710] In certain embodiments, heat sources may be used to generate apath for a flow of fluids between an injection well and a productionwell. The viscosity of heavy hydrocarbons at or near a heat source isreduced by the heat provided from the heat source. The reduced viscosityhydrocarbons may be immobile until a path is created for flow of thehydrocarbons. The path for flow of the hydrocarbons may be created byplacing an injection well and a production well at different positionsalong the length of the heat source and proximate the heat source. Apressurizing fluid provided through the injection well may produce aflow of the reduced viscosity hydrocarbons towards the production well.

[1711]FIG. 143 depicts a schematic of an embodiment for injecting apressurizing fluid in a formation. Heat source 508 may be placedsubstantially horizontally within opening 544 in hydrocarbon layer 522.The substantially horizontal portion of opening 544 may be placed in alower portion of hydrocarbon layer 522 and/or proximate the bottom ofthe hydrocarbon layer. Perforations 1680 may be located in the heel ofheat source 508. Injection wells 606 may be placed substantiallyvertically in hydrocarbon layer 522. At least one injection well 606 maybe placed near the toe of heat source 508. Another injection well 606may be placed proximate the midline of the horizontal section of heatsource 508. More or less injection wells 606 may be used depending on,for example, the size of hydrocarbon layer 522, a desired productionrate, etc.

[1712] Heat source 508 may provide heat to hydrocarbon layer 522 toreduce the viscosity of hydrocarbons in the formation. The viscosity ofhydrocarbons at or near heat source 508 decreases earlier thanhydrocarbons further away from the heat sources because of the radialpropagation of heat fronts away from the heat sources. A pressurizingfluid (e.g., steam) may be provided into the formation through injectionwells 606. The pressurizing fluid may produce a flow of the reducedviscosity hydrocarbons towards perforations 1680. Hydrocarbons and/orother fluids may be produced through perforations 1680 and from theformation along a length of opening 544. The produced fluids may befurther heated along the length of opening 544 by heat source 508 tomaintain produced fluids in a vapor phase and/or further crack producedfluids along the length of the heat source. The flow of fluids inhydrocarbon layer 522 are represented by the arrows in FIG. 143. Theflow may be controlled by an injection rate of the pressurizing fluidand/or a pressure in opening 544.

[1713]FIG. 144 depicts a schematic of another embodiment for injecting apressurizing fluid into hydrocarbon layer 522. As shown in FIG. 144,injection well 606 may be placed substantially horizontally inhydrocarbon layer 522. Injection well 606 may also be placed proximatethe top of hydrocarbon layer 522 and/or in an upper portion of thehydrocarbon layer. Heat source 508 may be placed substantiallyhorizontally within opening 544 in hydrocarbon layer 522. Thesubstantially horizontal portion of opening 544 may be placed in a lowerportion of hydrocarbon layer 522 and/or proximate the bottom of thehydrocarbon layer. Opening 544 may, in certain embodiments, be a casedopening with perforations 1680 placed proximate the toe of heat source508. The flow of reduced viscosity hydrocarbons produced by injection ofa pressurizing fluid (e.g., steam) may be along the length of heatsource 508 between an end of injection well 606 proximate opening 544and towards perforations 1680 as represented by the arrows in FIG. 144.Mobilized fluids (e.g., hydrocarbons, pressurizing fluid, etc.) may beproduced through perforations 1680. The produced fluids may be furtherheated along the length of opening 544 by heat source 508 to maintainproduced fluids in a vapor phase and/or further crack produced fluidsalong the length of the heat source.

[1714]FIG. 145A depicts a schematic of an embodiment for injecting apressurizing fluid into hydrocarbon layer 522. Injection well 606 may beplaced substantially horizontally within hydrocarbon layer 522.Injection well 606 may also be placed proximate the top of hydrocarbonlayer 522 and/or in an upper portion of the hydrocarbon layer. Heatsources 508 may be placed within opening 544 in hydrocarbon layer 522.Heat sources 508 may have toe portions that proximately meet, but do notnecessarily touch, near a midsection of the substantially horizontalportion of opening 544. The substantially horizontal portion of opening544 may be placed in a lower portion of hydrocarbon layer 522 and/orproximate the bottom of the hydrocarbon layer. Perforations 1680 may beplaced at or near the heel of one heat source 508. The flow of reducedviscosity hydrocarbons produced by injection of a pressurizing fluid(e.g., steam) through injection well 606 may be from proximate a topportion of one heat source 508 and along a length of opening 544 towardsperforations 1680 as shown by the arrows in FIG. 145A. Mobilized fluids(e.g., hydrocarbons, pressurizing fluid, etc.) may be produced throughperforations 1680. The produced fluids may be further heated along thelength of opening 544 by heat source 508 to maintain produced fluids ina vapor phase and/or further crack produced fluids along the length ofthe heat source.

[1715]FIG. 145B depicts a schematic of an embodiment for injecting apressurizing fluid into hydrocarbon layer 522. As shown by the arrows inFIG. 145B, fluids may be produced from an end of opening 544 opposite ofan end in which the fluids are produced in the embodiment of FIG. 145A.Producing the fluids as shown in FIG. 145B may increase the time thatproduced fluids are exposed to heat from heat sources 508. Increasingthe heating of the produced fluids may increase cracking and/orupgrading of the produced fluids.

[1716]FIG. 146 depicts a schematic of another embodiment for injecting apressurizing fluid into hydrocarbon layer 522. Injection well 606 may beplaced substantially vertically in hydrocarbon layer 522. Productionwell 512 may be placed substantially vertically in hydrocarbon layer522. In some embodiments, production well 512 may be heated to maintainproduced fluids in a vapor phase and/or further crack produced fluidsalong the length of the production well.

[1717] As shown in FIG. 146, heat source 508 may be placed substantiallyhorizontally within opening 544 in hydrocarbon layer 522. Thesubstantially horizontal portion of opening 544 may be placed in a lowerportion of hydrocarbon layer 522 and/or proximate the bottom of thehydrocarbon layer. Opening 544 may, in certain embodiments, be a casedopening. The flow of reduced viscosity hydrocarbons produced byinjection of a pressurizing fluid (e.g., steam) may be along the lengthof heat source 508 between an end of injection well 606 proximate theheel of the heat source and towards an end of production well 512proximate the toe of the heat source as represented by the arrows inFIG. 146. Mobilized fluids (e.g., hydrocarbons, pressurizing fluid,etc.) may be produced through perforations 1680 in production well 512.

[1718] In an embodiment, after a flow of hydrocarbons has been createdin hydrocarbon layer 522, heat sources 508 may be turned down and/oroff. Turning down and/or off heat sources 508 may save on energy costsfor producing fluids from the formation. Fluids may continue to beproduced from hydrocarbon layer 522 using injection of pressurizingfluid to mobilize and sweep fluids towards perforations 1680 and/orproduction well 512. In certain embodiments, the pressurizing fluid maybe heated to elevated temperatures at the surface (e.g., in a heatexchange unit). The heated pressurizing fluid may be used to providesome heat to hydrocarbon layer 522. In an embodiment, heatedpressurizing fluid may be used to maintain a temperature in theformation after reducing and/or turning off heat provided by heatsources 508.

[1719] Providing the pressurizing fluid in the selected section mayincrease sweeping of hydrocarbons from the formation (i.e., increase thetotal amount of hydrocarbons heated and produced in the formation).Increased sweeping of hydrocarbons in the formation may increase totalhydrocarbon recovery from the formation. In some embodiments, greaterthan about 50% by weight of the initial estimated mass of hydrocarbonsmay be produced from the formation. In other embodiments, greater thanabout 60% by weight or greater than about 70% by weight of the initialestimated mass of hydrocarbons may be produced from the formation.

[1720] In an embodiment, greater than about 60% by volume of the initialvolume in place of hydrocarbons in the formation are produced. In otherembodiments, greater than about 70% by volume or greater than about 80%by volume of the initial volume in place of hydrocarbons may be producedfrom a formation.

[1721] In an embodiment, a portion of a relatively permeable formationmay be heated to increase a partial pressure of H₂. The partial pressureof H₂ may be measured at a production well, a monitoring well, a heaterwell and/or an injection well. In some embodiments, an increased H₂partial pressure may include H₂ partial pressures in a range from about0.5 bars absolute to about 7 bars absolute. Alternatively, an increasedH₂ partial pressure range may include H₂ partial pressures in a rangefrom about 5 bars absolute to about 7 bars absolute. For example, amajority of hydrocarbon fluids may be produced wherein a H₂ partialpressure is within a range of about 5 bars absolute to about 7 barsabsolute. A range of H₂ partial pressures within the pyrolysis H₂partial pressure range may vary depending on, for example, temperatureand pressure of the heated portion of the formation.

[1722] In an embodiment, pressure within a formation may be controlledto enhance production of hydrocarbons of a desired carbon numberdistribution. Low formation pressure may favor production ofhydrocarbons having a high carbon number distribution (e.g., condensablehydrocarbons). Low pressure in the formation may reduce the cracking ofhydrocarbons into lighter hydrocarbons. Thus, reducing pressure in theformation may increase the production of condensable hydrocarbons andlower the production of non-condensable hydrocarbons. Operating at lowerpressure in the formation may inhibit the production of carbon dioxidein the formation and/or increase the recovery of hydrocarbons from theformation.

[1723] Pressure within a relatively permeable formation may becontrolled and/or reduced by creating a pressure sink within theformation. In an embodiment, a first section of the formation may beheated prior to other sections (i.e., adjacent sections) of theformation. At least some hydrocarbons within the first section may bepyrolyzed during heating of the first section. Pyrolyzed hydrocarbons(e.g., light hydrocarbons) from the first section may be produced beforeor during start-up of heating in other sections (i.e., during earlytimes of heating before temperatures within the other sections reachpyrolysis temperatures). In some embodiments, some un-pyrolyzedhydrocarbons (e.g., heavy hydrocarbons) may be produced from the firstsection. The un-pyrolyzed hydrocarbons may be produced during earlytimes of heating when temperatures within the first section are belowpyrolysis temperatures. Producing fluid from the first section mayestablish a pressure gradient in the formation with the lowest pressurelocated at the production wells.

[1724] When a section of formation adjacent to the first section isheated, heat applied to the formation may mobilize the hydrocarbons.Mobilized liquid hydrocarbons may move downwards by gravity drainage.Mobilized vapor hydrocarbons may move towards the first section due to apressure gradient caused by production of fluids from the first section.Movement of mobilized vapor hydrocarbons towards the first section mayinhibit excess pressure buildup in the sections being heated and/orpyrolyzed. Temperature of the first section may be maintained above acondensation temperature of desired hydrocarbon fluids that are to beproduced from the production wells in the first section.

[1725] Producing fluids from other sections through production wells inthe first section may reduce the number of production wells needed toproduce fluids from a formation. Pressure in the other sections (e.g.,pressures at and adjacent to heat sources in the other sections) of theformation may remain low. Low formation pressure may be maintained evenin relatively deep relatively permeable formations. For example, aformation pressure may be maintained below about 15 bars absolute in aformation that is about 220 m below the surface.

[1726] Controlling the pressure in the sections being heated may inhibitcasing collapse in the heat sources. Controlling the pressure in thesections being heated may inhibit excessive coke formation on andadjacent to the heat sources. Pressure in the sections being heated maybe controlled by controlling production rate of fluid from productionwells in adjacent sections and/or by releasing pressure at or adjacentto heat sources in the section being heated.

[1727]FIG. 147 depicts a cross-sectional representation of an embodimentfor treating a relatively permeable formation. Heat sources 508 may beused to provide heat to sections 1682, 1684, 1686 of hydrocarbon layer522. Heat sources 508 may be placed in a similar pattern as shown in theembodiment of FIG. 140. Production well 512 may be placed a center offirst section 1682. Production well 512 may be placed substantiallyhorizontally within first section 1682. Other locations and/ororientations for production well 512 may be used depending on, forexample, a desired production rate, a desired product quality orcharacteristic, etc.

[1728] In an embodiment, heat may be provided to first section 1682 fromheat sources 508. Heat provided to first section 1682 may mobilize atleast some hydrocarbons within the first section. Hydrocarbons withinfirst section 1682 may be mobilized at temperatures above about 50° C.or, in some embodiments, above about 75° C. or above about 100° C. In anembodiment, production of mobilized hydrocarbons may be inhibited untilpyrolysis temperatures are reached in first section 1682. Inhibiting theproduction of hydrocarbons while increasing temperature within firstsection 1682 tends to increase the pressure within the first section. Insome embodiments, at least some mobilized hydrocarbons may be producedthrough production well 512 to inhibit excessive pressure buildup in theformation. The produced mobilized hydrocarbons may include heavyhydrocarbons, liquid-phase light hydrocarbons, and/or un-pyrolyzedhydrocarbons. In certain embodiments, only a portion of the mobilizedhydrocarbons is produced, such that the pressure in first section 1682is maintained below a selected pressure. The selected pressure may be,for example, a lithostatic pressure, a hydrostatic pressure, or apressure selected to produce a desired product characteristic.

[1729] In an embodiment, heat may be provided to first section 1682 fromheat sources 508 to increase temperatures within the first section topyrolysis temperatures. Pyrolysis temperatures may include temperaturesabove about 250° C. In some embodiments, pyrolysis temperatures may beabove about 270° C., 300° C., or 325° C. Pyrolyzed hydrocarbons fromfirst section 1682 may be produced through production well 512 orproduction wells. During production of hydrocarbons through productionwell 512 or production wells, heat may be provided to second sections1684 from heat sources 508 to mobilize hydrocarbons within the secondsection. Further heating of second sections 1684 may pyrolyze at leastsome hydrocarbons within the second section. Heat may also be providedto third sections 1686 from heat sources 508 to mobilize and/or pyrolyzehydrocarbons within the third section. In some embodiments, heat sources508 in third sections 1686 may be turned on after heat sources 508 insecond sections 1684. In other embodiments, heat sources 508 in thirdsections 1686 are turned on simultaneously with heat sources 508 insecond sections 1684.

[1730] Producing hydrocarbons from first section 1682 at production well512 or production wells may create a pressure sink at the productionwell. The pressure sink may be a low pressure zone around productionwell 512 or production wells as compared to the pressure in theformation. Fluids from second sections 1684 and third sections 1686 mayflow towards production well 512 or production wells because of thepressure sink at the production well. The fluids that flow towardsproduction well 512 may include at least some vapor phase lighthydrocarbons. In some embodiments, the fluids may include some liquidphase hydrocarbons. The flow of fluids towards production well 512 maymaintain lower pressures in second sections 1684 and third sections 1686than if the fluids remain within these sections and are heated to highertemperatures. In addition, fluids that flow towards production well 512may have a shorter residence time in the heated sections and undergoless pyrolyzation than fluids that remain within the heated sections. Atleast a portion of fluids from second sections 1684 and/or thirdsections 1686 may be produced through production well 512. In certainembodiments, one or more production wells may be placed in secondsections 1684 and/or third sections 1686 to produce at least somehydrocarbons from these sections.

[1731] After substantial production of the hydrocarbons that areinitially present in each of the sections (first section 1682, secondsections 1684, and third sections 1686), heat sources 508 in each of thesections may be turned down and/or off to reduce the heat provided tothe section. Turning down and/or off heat sources 508 may reduce energyinput costs for heating the formation. In addition, turning down and/oroff heat sources 508 may inhibit further cracking of hydrocarbons as thehydrocarbons flow towards production well 512 and/or other productionwells in the formation. In an embodiment, heat sources 508 in firstsection 1682 are turned off before heat sources 508 in second sections1684 or heat sources 508 in third sections 1686. The time and durationeach heat source 508 in each section 1682, 1684, 1686 is turned on maybe determined based on experimental and/or simulation data.

[1732] The flow of fluids towards production well 512 may increase therecovery of hydrocarbons from the formation. Generally, decreasing thepressure in the formation tends to increase the cumulative recovery ofhydrocarbons from the formation and decrease the production ofnon-condensable hydrocarbons from the formation. Decreasing theproduction of non-condensable hydrocarbons may result in a decrease inthe API gravity of a mixture produced from the formation. In someembodiments, a pressure may be selected to balance a desired API gravityin the produced mixture with a recovery of hydrocarbons from theformation. The flow of fluids towards production well 512 may increase asweep efficiency of hydrocarbons from the formation. Increased sweepefficiency may result in increased recovery of hydrocarbons from theformation.

[1733] In certain embodiments, pressure within the formation may beselected to produce a mixture from the formation with a desired quality.Pressure within the formation may be controlled by, for example,controlling heating rates within the formation, controlling theproduction rate through production well 512 or production wells,controlling the time for turning on heat sources 508, controlling theduration for using heat sources 508, etc. Pressures within the formationalong with other operating conditions (e.g., temperature, productionrate, etc.) may be selected and controlled to produce a mixture withdesired qualities. In certain embodiments, pressure and/or otheroperating conditions in the formation may be selected based on a pricecharacteristic of the produced mixture.

[1734] In some embodiments, one or more injection wells may be placed inthe formation. The one or more injection wells may be used to inject apressurizing fluid into the formation. Injecting a pressurizing fluidinto the formation may be used to increase the recovery of hydrocarbonsfrom the formation and/or to increase a pressure in the formation.Controlling the flow rate of pressurizing fluid may control pressure inthe formation.

[1735] In certain embodiments, a substantial portion of hydrocarbonsfrom a formation may be recovered (i.e., produced) in a single pass insitu recovery process. A single pass in situ recovery process mayinclude staged heating of the formation and/or a single step ofinjecting fluid into the formation. Typically, multiple pass processes(e.g., secondary or tertiary pass processes) include multiple steps ofinjecting liquids or gases into a formation to promote recovery from theformation. For example, steam flood recovery from a tar sands formationmay include more than one step of injecting steam into the formationand/or recycling of fluids (e.g., steam or product fluids) back into theformation for further recovery. The recovery efficiency for hydrocarbonsin a single pass in situ recovery process may be improved compared tothe recovery efficiency of multiple fluid injection step processes. Inaddition, a single pass in situ recovery process may produce arelatively flat production rate through the process. The relatively flatproduction rate may reduce or minimize treatment facility requirementsneeded for treatment of product fluids. Typically, large treatmentfacilities are required in multiple step processes for the large initialproduction of fluid, while during subsequent production steps theproduction rate steeply decreases resulting in unused treatment facilitycapacity.

[1736] Producing formation fluids in the upper portion of the formationmay allow for production of hydrocarbons substantially in a vapor phase.Lighter hydrocarbons may be produced from production wells placed in theupper portion of the hydrocarbon containing formation. Hydrocarbonsproduced from an upper portion of the formation may be upgraded ascompared to hydrocarbons produced from a lower portion of the formation.Producing through wells in the upper portion may also inhibit coking ofproduced fluids at the production wellbore. Producing through wellsplaced in a lower portion of the formation may produce a heavierhydrocarbon fluid than is produced in the upper portion of theformation. The heavier hydrocarbon fluid may contain substantial amountsof cold bitumen or tar. Cold bitumen or tar production tends to bedecreased when producing through wells placed in the upper portion ofthe formation. In some embodiments, the upper portion of the formationmay include an upper half of the formation. However, a size of the upperportion may vary depending on several factors (e.g., a thickness of theformation, vertical permeability of the formation, a desired quality ofproduced fluid, or a desired production rate).

[1737] In some embodiments, a quality of a mixture produced from aformation is controlled by varying a location for producing the mixturewithin the formation. The quality of the mixture produced may be ratedon a variety of factors (e.g., API gravity of the mixture, carbon numberdistribution, a weight ratio of components in the mixture, and/or apartial pressure of hydrogen in the mixture). Other qualities of themixture may include, but are not limited to, a ratio of heavyhydrocarbons to light hydrocarbons in the mixture and/or a ratio ofaromatics to paraffins in the mixture. In one embodiment, the locationfor producing the mixture is varied by varying a location of aproduction well within the formation. For example, the quality of themixture can be varied by varying a distance between a production welland a heat source. Locating the production well closer to the heatsource may increase cracking at or near the production well, thus,increasing, for example, an API gravity of the mixture produced. In someembodiments, a number of production wells in a portion of the formationor a production rate from a portion of the formation may be used tocontrol the quality of a mixture produced.

[1738] In some embodiments, varying a location for production includesvarying a portion of the formation from which the mixture is produced.For example, a mixture may be produced from an upper portion of theformation, a middle portion of the formation, and/or a lower portion ofthe formation at various times during production from a formation.Varying the portion of the formation from which the mixture is producedmay include varying a depth of a production well within the formationand/or varying a depth for producing the mixture within a productionwell. In certain embodiments, the quality of the produced mixture isincreased by producing in an upper portion of the formation rather thana middle or lower portion of the formation. Producing in the upperportion tends to increase the amount of vapor phase and/or lighthydrocarbon production from the formation. Producing in lower portionsof the formation may decrease a quality of the produced mixture;however, a total mass recovery from the formation and/or a portion ofthe formation selected for treatment (i.e., a weight percentage ofinitial mass of hydrocarbons in the formation, or in the selectedportion, produced) can be increased by producing in lower portions(e.g., the middle portion or lower portion of the formation). Producingin the lower portion may, in some embodiments, provide the highest totalmass recovery, energy recovery, and/or a better energy balance.

[1739] In certain embodiments, an upper portion of the formationincludes about one-third of the formation closest to an overburden ofthe formation. The upper portion of the formation, however, may includeup to about 35%, 40%, or 45% of the formation closest to the overburden.A lower portion of the formation may include a percentage of theformation closest to an underburden, or base rock, of the formation thatis substantially equivalent to the percentage of the formation that isincluded in the upper portion. A middle portion of the formation mayinclude the remainder of the formation between the upper portion and thelower portion. For example, the upper portion may include aboutone-third of the formation closest to the overburden while the lowerportion includes about one-third of the formation closest to theunderburden and the middle portion includes the remaining third of theformation between the upper portion and the lower portion. FIG. 148(described below) depicts embodiments of upper portion 1688, middleportion 1690, and lower portion 1692 in hydrocarbon layer 522 along withproduction well 512.

[1740] In some embodiments, the lower portion includes a differentpercentage of the formation than the upper portion. For example, theupper portion may include about 30% of the formation closest to theoverburden while the lower portion includes about 40% of the formationclosest to the underburden and the middle portion includes the remaining30% of the formation. Percentages of the formation included in theupper, middle, and lower portions of the formation may vary dependingon, for example, placement of heat sources in the formation, spacing ofheat sources in the formation, a structure of the formation (e.g.,impermeable layers within the formation), etc. In some embodiments, aformation may include only an upper portion and a lower portion. Inaddition, the percentages of the formation included in the upper,middle, and lower portions of the formation may vary due to variation ofpermeability within the formation. In some formations, permeability mayvary vertically within the formation. For example, the permeability inthe formation may be lower in an upper portion of the formation than alower portion of the formation.

[1741] In some cases, the upper, middle, and lower portions of ahydrocarbon containing formation may be determined by characteristics ofthe portions. For example, a middle portion may include a portion thatis high enough within the formation to not allow heavy hydrocarbons tosettle in the portion after at least some hydrocarbons have beenmobilized. A bottom portion may be a portion where the heavyhydrocarbons are substantially settled after mobilization due to gravitydrainage. A top portion may be a portion where production issubstantially vapor phase production after mobilization of at least someheavy hydrocarbons.

[1742] In an embodiment, selecting the location for producing a mixturefrom a formation includes selecting the location based on a pricecharacteristic for the produced mixture. The price characteristic may bea price characteristic of hydrocarbons produced from the formation. Theprice characteristic may be determined by multiplying a production rateof the produced mixture at a selected API gravity by a price obtainablefor selling the produced mixture with the selected API gravity. In someembodiments, the price characteristic may be determined as a function ofthe API gravity of the produced mixture, the total mass recovery fromthe formation, a price obtainable for selling the produced mixture,and/or other factors affecting production of the mixture from theformation. Other characteristics, however, may also be included in theprice characteristic. For example, other characteristics may include,but are not limited to, a selling price of hydrocarbon components in theproduced mixture, a selling price of sulfur produced, a selling price ofmetals produced, a ratio of paraffins to aromatics produced, and/or aweight percentage of heavy hydrocarbons in the mixture.

[1743] In some instances, the price characteristic may change duringproduction of the mixture from the formation. The price characteristicmay change, for example, based on a change in the selling price of theproduced mixture or of a hydrocarbon component in the mixture. In such acase, a parameter for producing the mixture may be adjusted based on thechange in the price characteristic. In an embodiment, the parameter forproducing the mixture is a location for producing the mixture within theformation.

[1744] In some embodiments, the parameter may include operatingconditions within the formation that are controlled based on the pricecharacteristic. Operating conditions may include parameters such as, butnot limited to, pressure, temperature, heating rate, and heat outputfrom one or more heat sources. Operating conditions within the formationmay be adjusted based on a change in the price characteristic duringproduction of the mixture from the formation.

[1745] In certain embodiments, the price characteristic may be based ona relationship between cumulative oil (hydrocarbon) recovery and APIgravity. Generally, increasing the API gravity produced from a formationby an in situ conversion process tends to decrease the cumulativehydrocarbon recovery from the formation (i.e., total mass recovery). Inan embodiment, the relationship between API gravity of the producedhydrocarbons and total mass recovery is a linear relationship. Thelinear relationship may be based on, for example, experimental data(e.g., pyrolysis data) and/or simulation data (e.g., STARS simulationdata).

[1746]FIG. 149 depicts linear relationships between total mass recovery(recovery (vol %)) versus API gravity (°) of the produced hydrocarbonsfor three different tar sands formations. Athabasca (Canada) tar sands1694 shows the highest recovery for a value of API gravity. Athabascashows the highest recovery because Athabasca tar sands have the highestinitial API gravity. Cerro Negro (Venezuela) tar sands 1696 shows aslightly lower recovery for a value of API gravity. Santa Cruz (UnitedStates) tar sands 1698 shows the lowest recovery for a value of APIgravity. Santa Cruz shows the lowest recovery because Santa Cruz tarsands have the lowest initial API gravity. Other hydrocarbon containingformations may be tested similarly to produce similar plots. Theserelationships may be used to determine a desired operating range fortreating a hydrocarbon containing formation. For example, the linearrelationship between recovery and API gravity may be used to determine abest operating range (e.g., a desired API gravity produces a specificrecovery value) based on market conditions such as the price of oil.

[1747] In an embodiment, a location from which the mixture is producedis varied by varying a production depth within a production well. Themixture may be produced from different portions of, or locations in, theformation to control the quality of the produced mixture. A productiondepth within a production well may be adjusted to vary a portion of theformation from which the mixture is produced. In some embodiments, theproduction depth is determined before producing the mixture. from theformation. In other embodiments, the production depth may be adjustedduring production of the mixture to control the quality of the producedmixture. In certain embodiments, production depth within a productionwell includes varying a production location along a length of theproduction wellbore. For example, the production location may be at anydepth along the length of a substantially vertical production wellborelocated within the formation or at any position along the length of asubstantially horizontal production wellbore. Changing the depth of theproduction location within the formation may change a quality of themixture produced from the formation.

[1748] In some embodiments, varying the production location within aproduction well includes varying a packing height within the productionwell. For example, the packing height may be changed within theproduction well to change the portion of the production well thatproduces fluids from the formation. Packing within the production welltends to inhibit production of fluids at locations where the packing islocated. In other embodiments, varying the production location within aproduction well includes varying a location of perforations on theproduction wellbore used to produce the mixture. Perforations on theproduction wellbore may be used to allow fluids to enter into theproduction well. Varying the location of these perforations may change alocation or locations at which fluids can enter the production well.

[1749]FIG. 148 depicts a cross-sectional representation of an embodimentof production well 512 placed in hydrocarbon layer 522. Hydrocarbonlayer 522 may include upper portion 1688, middle portion 1690, and lowerportion 1692. Production well 512 may be placed within all threeportions 1688, 1690, 1692 within hydrocarbon layer 522 or within onlyone or more portions of the formation. As shown in FIG. 148, productionwell 512 may be placed substantially vertically within hydrocarbon layer522. Production well 512, however, may be placed at other angles (e.g.,horizontal or at other angles between horizontal and vertical) withinhydrocarbon layer 522 depending on, for example, a desired productmixture, a depth of overburden 524, a desired production rate, etc.

[1750] Packing material 1100 may be placed within production well 512.Packing material 1100 tends to inhibit production of fluids at locationsof the packing within the wellbore (i.e., fluids are inhibited fromflowing into production well 512 at the packing material). A height ofpacking material 1100 within production well 512 may be adjusted to varythe depth in the production well from which fluids are produced. Forexample, increasing the packing height decreases the maximum depth inthe formation at which fluids may be produced through production well512. Decreasing the packing height will increase the depth forproduction. In some embodiments, layers of packing material 1100 may beplaced at different heights within the wellbore to inhibit production offluids at the different heights. Conduit 1700 may be placed throughpacking material 1100 to produce fluids entering production well 512beneath the packing layers.

[1751] One or more perforations 1680 may be placed along a length ofproduction well 512. Perforations 1680 may be used to allow fluids toenter into production well 512. In certain embodiments, perforations1680 are placed along an entire length of production well 512 to allowfluids to enter into the production well at any location along thelength of the production well. In other embodiments, locations ofperforations 1680 may be varied to adjust sections along the length ofproduction well 512 that are used for producing fluids from theformation. In some embodiments, one or more perforations 1680 may beclosed (shut-in) to inhibit production of fluids through the one or moreperforations. For example, a sliding member may be placed overperforations 1680 that are to be closed to inhibit production. Certainperforations 1680 along production well 512 may be closed or opened atselected times to allow production of fluids at different locationsalong the production well at the selected times.

[1752] In one embodiment, a first mixture is produced from upper portion1688. A second mixture may be produced from middle portion 1690. A thirdmixture may be produced from lower portion 1692. The first, second, andthird mixtures may be produced at different times during treatment ofthe formation. For example, the first mixture may be produced before thesecond mixture or the third mixture and the second mixture may beproduced before the third mixture. In certain embodiments, the firstmixture is produced such that the first mixture has an API gravitygreater than about 20°. The second mixture or the third mixture may alsobe produced such that each mixture has an API gravity greater than about20°. A time at which each mixture is produced with an API gravitygreater than about 20° may be different for each of the mixtures. Forexample, the first mixture may be produced at an earlier time thaneither the second or the third mixture. The first mixture may beproduced earlier because the first mixture is produced from upperportion 1688. Fluids in upper portion 1688 tend to have a higher APIgravity at earlier times than fluids in middle portion 1690 or lowerportion 1692 due to gravity drainage of heavier fluids (e.g., heavyhydrocarbons) in the formation and/or higher vapor phase production inhigher portions of the formation.

[1753] In an embodiment, a fluid produced from a portion of a relativelypermeable formation by an in situ process may include nitrogencontaining compounds. For example, less than about 0.5 weight % of thecondensable fluid may include nitrogen containing compounds or, forexample, less than about 0.1 weight % of the condensable fluid mayinclude nitrogen containing compounds. In addition, a fluid produced byan in situ process may include oxygen containing compounds (e.g.,phenolics). For example, less than about 1 weight % of the condensablefluid may include oxygen containing compounds or, for example, less thanabout 0.5 weight % of the condensable fluid may include oxygencontaining compounds. A fluid produced from a relatively permeableformation may also include sulfur containing compounds. For example,less than about 5 weight % of the condensable fluid may include sulfurcontaining compounds or, for example, less than about 3 weight % of thecondensable fluid may include sulfur containing compounds. In someembodiments, a weight percent of nitrogen containing compounds, oxygencontaining compounds, and/or sulfur containing compounds in acondensable fluid may be decreased by increasing a fluid pressure in arelatively permeable formation during an in situ process.

[1754] In an embodiment, condensable hydrocarbons of a fluid producedfrom a relatively permeable formation may include aromatic compounds.For example, greater than about 20 weight % of the condensablehydrocarbons may include aromatic compounds. In another embodiment, anaromatic compound weight percent may include greater than about 30weight % of the condensable hydrocarbons. The condensable hydrocarbonsmay also include di-aromatic compounds. For example, less than about 20weight % of the condensable hydrocarbons may include di-aromaticcompounds. In another embodiment, di-aromatic compounds may include lessthan about 15 weight % of the condensable hydrocarbons. The condensablehydrocarbons may also include tri-aromatic compounds. For example, lessthan about 4 weight % of the condensable hydrocarbons may includetri-aromatic compounds. In another embodiment, less than about 1 weight% of the condensable hydrocarbons may include tri-aromatic compounds.

[1755] In certain embodiments, some precipitation and/or non-dissolutionof asphaltenes may occur in heavy hydrocarbons and/or heavy hydrocarbonsmixed with light hydrocarbons within a relatively permeable formationduring a recovery process. Precipitation and/or non-dissolution of theasphaltenes may increase the quality of hydrocarbons produced from theformation. In some cases, the precipitated and/or non-dissolvedasphaltenes may be produced through further heating of the formationand/or injection of recovery fluid into the formation (e.g., injectionof a light hydrocarbon mixture or blending agent to form a produciblemixture including the asphaltenes).

[1756] In some embodiments, hydrocarbon fluids produced from ahydrocarbon containing formation may have a relatively low acid number.“Acid number” is defined as the number of milligrams of KOH (potassiumhydroxide) required to neutralize one gram of oil (i.e., bring the oilto a pH of 7). Higher acid hydrocarbon fluids (e.g., greater than about1 mg/gram KOH) are typically more expensive to refine and generallyconsidered to have a less desirable quality. Generally, fluids with acidnumbers less than about 1 are desired. Heavy hydrocarbon fluids producedfrom hydrocarbon containing formations using standard productiontechniques such as cold production or steam flooding may have a highacid number due to the presence of naphthenic, humic, or other acids inthe produced hydrocarbons. Hydrocarbon fluids produced from a formationusing an in situ recovery process (e.g., pyrolyzed fluids) may have alower acid number due to acid-reducing reactions during heating of theformation. For example, decarboxylation may reduce the amount ofcarboxylic acids in the formation during heating/pyrolyzation. In anembodiment, hydrocarbon fluids produced from a relatively permeableformation have an acid number near zero. In certain embodiments,hydrocarbon fluids produced from a formation have acid numbers less thanabout 1 mg/gram KOH, less than about 0.8 mg/gram KOH, less than about0.6 mg/gram KOH, less than about 0.5 mg/gram KOH, less than about 0.25mg/gram KOH, or less than about 0.1 mg/gram KOH.

[1757] In certain embodiments, a portion of the formation proximate aproduction well may be hotter than other portions of the formation(e.g., an average temperature above about 300° C.). The increasedtemperature of the portion of the formation proximate the productionwell may be produced by additional heat provided by a heater placedwithin the production well, an additional heat source proximate theproduction well, and/or natural heating within the portion. Having anincreased temperature in the portion proximate the production well mayincrease and/or upgrade a quality of hydrocarbons produced through theproduction well (e.g., by increased cracking or thermal upgrading of thehydrocarbons). In addition, a quality of hydrocarbons produced may befurther increased by cracking of hydrocarbons or reaction ofhydrocarbons within the production well.

[1758] Increasing heating proximate a production well, however, mayincrease the possibility of coking at the production well. In someembodiments, operating conditions within the formation may be controlledto inhibit coking of a production well. In one embodiment, heat outputfrom a heat source proximate the production well may be controlled toinhibit coking of the production well. For example, the heat source canbe turned down and/or off when conditions (e.g., temperature) at theproduction well begin to favor coking at the production well. Forexample, coke may form at temperatures above about 400° C. In certainembodiments, heat provided from the heat source may be turned downand/or off during a time at which a mixture is produced through theproduction well. The heat provided may be turned on and/or increasedwhen the quality of produced fluid is below a desired quality. Inanother embodiment, a production well is located at a sufficientdistance from each of the heat sources in the formation such that atemperature at the production well inhibits coking at the productionwell.

[1759] In other embodiments, steam may be added to the formation byadding water or steam through a conduit in a production well or otherwellbore. In some embodiments, steam may be produced by evaporation ofwater within the formation. The additional steam may inhibit cokeformation proximate the production well. The steam may react with thecoke to form carbon dioxide, carbon monoxide, and/or hydrogen. Incertain embodiments, air may be periodically injected through a conduit(e.g., a conduit in a production well) to oxidize any coke formed at ornear a production well.

[1760] In an embodiment of a system using heat sources, a material(e.g., a cement and/or polymer foam) may be injected into the formationto inhibit fingering and/or breakthrough of gases within the formation.The material may inhibit fluid flow through channels adjacent to theheat sources. The use of such a material may provide a more uniform flowof mobilized fluids and increase the recovery of fluids from theformation.

[1761] An in situ process may be used to provide heat to mobilize and/orpyrolyze hydrocarbons within a relatively permeable formation to producehydrocarbons from the formation that are not technically or economicallyproducible using current production techniques such as surface mining,solution extraction, steam injection, etc. Such hydrocarbons may existin relatively deep, relatively permeable formations. For example, suchhydrocarbons may exist in a relatively permeable formation that isgreater than about 500 m below a ground surface but less than about 700m below the surface. Hydrocarbons within these relatively deep,relatively permeable formations may still be at a relatively cooltemperature such that the hydrocarbons are substantially immobile.Hydrocarbons found in deeper formations (e.g., a depth greater thanabout 700 m below the surface) may be somewhat more mobile due toincreased natural heating of the formations as formation depth increasesbelow the surface. Typically, the temperature in the formation increasesabout 2° C. to about 4° C. for every 100 meters in depth below thesurface. The temperature at a certain depth may vary, however, dependingon, for example, the surface temperature which may be anywhere fromabout −5° C. to about 30° C. Hydrocarbons may be more readily producedfrom these deeper formations because of their mobility. However, thesehydrocarbons will generally be heavy hydrocarbons with an API gravitybelow about 20°. In some embodiments, the API gravity may be below about15° or below about 10°.

[1762] Heavy hydrocarbons produced from a relatively permeable formationmay be mixed with light hydrocarbons so that the heavy hydrocarbons canbe transported to a treatment facility (e.g., pumping the hydrocarbonsthrough a pipeline). In some embodiments, the light hydrocarbons (suchas naphtha or gas condensate) are brought in through a second pipeline(or are trucked) from other areas (such as a treatment facility oranother production site) to be mixed with the heavy hydrocarbons. Thecost of purchasing and/or transporting the light hydrocarbons to aformation site can add significant cost to a process for producinghydrocarbons from a formation. In an embodiment, producing the lighthydrocarbons at or near a formation site (e.g., less than about 100 kmfrom the formation site) that produces heavy hydrocarbons instead ofusing a second pipeline for supply of the light hydrocarbons may allowfor use of the second pipeline for other purposes. The second pipelinemay be used, in addition to a first pipeline already used for pumpingproduced fluids, to pump produced fluids from the formation site to atreatment facility. Use of the second pipeline for this purpose mayfurther increase the economic viability of producing light hydrocarbons(i.e., blending agents) at or near the formation site. Another option isto build a treatment facility or refinery at a formation site. However,this can be expensive and, in some cases, not possible.

[1763] In an embodiment, light hydrocarbons (e.g., a blending agent) maybe produced at or near a formation site that produces heavy hydrocarbons(i.e., near the production site of heavy hydrocarbons). The lighthydrocarbons may be mixed with heavy hydrocarbons to produce atransportable mixture. The transportable mixture may be introduced intoa first pipeline used to transport fluid to a remote refinery ortransportation facility, which may be located more than about 100 kmfrom the production site. The transportable mixture may also beintroduced into a second pipeline that was previously used to transporta blending agent (e.g., naphtha, condensate, etc.) to or near theproduction site. Producing the blending agent at or near the productionsite may allow the ability to significantly increase throughput to theremote refinery or transportation facility without installation ofadditional pipelines. Additionally, the blending agent used may-berecovered and sold from the refinery instead of being transported backto the heavy hydrocarbon production site. The transportable mixture mayalso be used as a raw material feed for a production process at theremote refinery.

[1764] Throughput of heavy hydrocarbons to an existing remote treatmentfacility may be a limiting factor in embodiments that use a two pipelinesystem with one of the pipelines dedicated to transporting a blendingagent to the heavy hydrocarbon production site. Using a blending agentproduced at or near the heavy hydrocarbon production site may allow fora significant increase in the throughput of heavy hydrocarbons to theremote treatment facility. For example, a pair of pipelines with ablending agent to heavy hydrocarbon ratio of 1:2 may transport twice asmuch oil if recycling of the blending agent is not necessary. In someembodiments, the blending agent may be used to clean tanks, pipes,wellbores, etc. The blending agent may be used for such purposes withoutprecipitating out components (e.g., asphaltenes or waxes) cleaned fromthe tanks, pipes, or wellbores.

[1765] In an embodiment, heavy hydrocarbons are produced as a firstmixture from a first section of a relatively permeable formation. Heavyhydrocarbons may include hydrocarbons with an API gravity below about20°, 15°, or 10°. Heat provided to the first section may mobilize atleast some hydrocarbons within the first section. The first mixture mayinclude at least some mobilized hydrocarbons from the first section.Heavy hydrocarbons in the first mixture may include a relatively highasphaltene content compared to saturated hydrocarbon content. Forexample, heavy hydrocarbons in the first mixture may include anasphaltene content to saturated hydrocarbon content ratio greater thanabout 1, greater than about 1.5, or greater than about 2.

[1766] Heat provided to a second section of the formation may pyrolyzeat least some hydrocarbons within the second section. A second mixturemay be produced from the second section. The second mixture may includeat least some pyrolyzed hydrocarbons from the second section. Pyrolyzedhydrocarbons from the second section may include light hydrocarbonsproduced in the second section. The second mixture may includerelatively higher amounts (as compared to heavy hydrocarbons orhydrocarbons found in the formation) of hydrocarbons such as naphtha,methane, ethane, or propane (i.e., saturated hydrocarbons) and/oraromatic hydrocarbons. In some embodiments, light hydrocarbons mayinclude an asphaltene content to saturated hydrocarbon content ratioless than about 0.5, less than about 0.05, or less than about 0.005.

[1767] A condensable fraction of the light hydrocarbons of the secondmixture may be used as a blending agent. The presence of compounds inthe blending agent in addition to naphtha may allow the blending agentto dissolve a large amount of asphaltenes and/or solid hydrocarbons. Theblending agent may be used to clean tanks, pipelines or other vesselsthat have solid (or semi-solid) hydrocarbon deposits.

[1768] The light hydrocarbons of the second mixture may include lessnitrogen, oxygen, sulfur, and/or metals (e.g., vanadium or nickel) thanheavy hydrocarbons. For example, light hydrocarbons may have a nitrogen,oxygen, and sulfur combined weight percentage of less than about 5%,less than about 2%, or less than about 1%. Heavy hydrocarbons may have anitrogen, oxygen, and sulfur combined weight percentage greater thanabout 10%, greater than about 15%, or greater than about 18%. Lighthydrocarbons may have an API gravity greater than about 20°, greaterthan about 30°, or greater than about 40°.

[1769] The first mixture and the second mixture may be blended toproduce a third mixture. The third mixture may be formed in a treatmentfacility located at or near production facilities for the heavyhydrocarbons. The third mixture may have a selected API gravity. Theselected API gravity may be at least about 10° or, in some embodiments,at least about 20° or 30°. The API gravity may be selected to allow thethird mixture to be efficiently transported (e.g., through a pipeline).

[1770] A ratio of the first mixture to the second mixture in the thirdmixture may be determined by the API gravities of the first mixture andthe second mixture. For example, the lower the API gravity of the firstmixture, the more of the second mixture that may be needed to produce aselected API gravity in the third mixture. Likewise, if the API gravityof the second mixture is increased, the ratio of the first mixture tothe second mixture may be increased. In some embodiments, a ratio of thefirst mixture to the second mixture in the third mixture is at leastabout 3:1. Other ratios may be used to produce a third mixture with adesired API gravity. In certain embodiments, a ratio of the firstmixture to the second mixture is chosen such that a total mass recoveryfrom the formation will be as high as possible. In one embodiment, theratio of the first mixture to the second mixture may be chosen such thatat least about 50% by weight of the initial mass of hydrocarbons in theformation is produced. In other embodiments, at least about 60% byweight or at least about 70% by weight of the initial mass ofhydrocarbons may be produced. In some embodiments, the first mixture andthe second mixture are blended in a specific ratio that may increase thetotal mass recovery from the formation compared to production of onlythe second mixture from the formation (i.e., in situ processing of theformation to produce light hydrocarbons).

[1771] The ratio of the first mixture to the second mixture in the thirdmixture may be selected based on a desired viscosity, desired boilingpoint, desired composition, desired ratio of components (e.g., a desiredasphaltene to saturated hydrocarbon ratio-or a desired aromatichydrocarbon to saturated hydrocarbon ratio), and/or desired density ofthe third mixture. The viscosity and/or density may be selected suchthat the third mixture is transportable through a pipeline or usable ina treatment facility. In some embodiments, the viscosity (at about 4°C.) may be selected to be less than about 7500 centistokes (cs) lessthan about 2000 cs, less than about 100 cs, or less than about 10 cs.Centistokes is a unit of kinematic viscosity. Kinematic viscositymultiplied by the density yields absolute viscosity. The density (atabout 4° C.) may be selected to be less than about 1.0 g/cm³, less thanabout 0.95 g/cm³, or less than about 0.9 g/cm³. The asphaltene tosaturated hydrocarbon ratio may be selected to be less than about 1,less than about 0.9, or less than about 0.7. The aromatic hydrocarbon tosaturated hydrocarbon ratio may be selected to be less than about 4,less than about 3.5, or less than about 2.5.

[1772] The viscosity of a third mixture may have improved viscositycompared to conventionally produced crude oils. For example, in “TheViscosity of Air, Natural Gas, Crude Oil and Its Associated Gases at OilField Temperatures and Pressures” by Carlton Beal, AIME Transactions,vol. 165, p. 94, 1946, which is incorporated by reference as if fullyset forth herein. Beat found a correlation for 655 samples of crude oilthat indicates an average viscosity of about 50 centipoise (cp) at 38°C. for crude oil with an API gravity of 24°. The lowest averageviscosity was found to be about 20 cp at 38° C. for 200 California crudeoil samples with an API gravity of 24°. A third mixture produced bymixing of a first mixture and a second mixture may have a viscosity ofabout 11 cp at 38° C. and 24° API. Thus, a mixture produced by mixingheavy hydrocarbons with light hydrocarbons produced by an in situconversion process may have improved viscosity compared to typicalproduced crude oils.

[1773] In an embodiment, the ratio of the first mixture to the secondmixture in the third mixture is selected based on the relative stabilityof the third mixture. A component or components of the third mixture mayprecipitate out of the third mixture. For example, asphalteneprecipitation may be a problem for some mixtures of heavy hydrocarbonsand light hydrocarbons. Asphaltenes may precipitate when fluid isde-pressurized (e.g., removed from a pressurized formation or vessel)and/or there is a change in mixture composition. For the third mixtureto be transportable through a pipeline or usable in a treatmentfacility, the third mixture may need a minimum relative stability. Theminimum relative stability may include a ratio of the first mixture tothe second mixture such that asphaltenes do not precipitate out of thethird mixture at ambient and/or elevated temperatures. Tests may be usedto determine desired ratios of the first mixture to the second mixturethat will produce a relatively stable third mixture. For example,induced precipitation, chromatography, titration, and/or lasertechniques may be used to determine the stability of asphaltenes in thethird mixture. In some embodiments, asphaltenes precipitate out of amixture but are held suspended in the mixture and, hence, the mixturemay be transportable. A blending agent produced by an in situ processmay have excellent blending characteristics with heavy hydrocarbons(i.e., low probability for precipitation of heavy hydrocarbons from amixture with the blending agent).

[1774] In certain embodiments, resin content in the second mixture(i.e., light hydrocarbon mixture) may determine the stability of thethird mixture. For example, resins such as maltenes or resins containingheteroatoms such as N, S, or O may be present in the second mixture.These resins may enhance the stability of a third mixture produced bymixing a first mixture with the second mixture. In some cases, theresins may suspend asphaltenes in the mixture and inhibit asphalteneprecipitation.

[1775] In certain embodiments, market conditions may determinecharacteristics of a third mixture. Examples of market conditions mayinclude, but are not limited to, demand for a selected octane ofgasoline, demand for heating oil in cold weather, demand for a selectedcetane rating in a diesel oil, demand for a selected smoke point for jetfuel, demand for a mixture of gaseous products for chemical synthesis,demand for transportation fuels with a certain sulfur or oxygenatecontent, or demand for material in a selected chemical process.

[1776] In an embodiment, a blending agent may be produced from a sectionof a relatively permeable formation (e.g., a tar sands formation).“Blending agent” is a material that is mixed with another material toproduce a mixture having a desired property (e.g., viscosity, density,API gravity, etc.). The blending agent may include at least somepyrolyzed hydrocarbons. The blending agent may include properties of thesecond mixture of light hydrocarbons described above. For example, theblending agent may have an API gravity greater than about 20°, greaterthan about 30°, or greater than about 40°. The blending agent may beblended with heavy hydrocarbons to produce a mixture with a selected APIgravity. For example, the blending agent may be blended with heavyhydrocarbons with an API gravity below about 15° to produce a mixturewith an API gravity of at least about 20°. In certain embodiments, theblending agent may be blended with heavy hydrocarbons to produce atransportable mixture (e.g., movable through a pipeline). In someembodiments, the heavy hydrocarbons are produced from another section ofthe relatively permeable formation. In other embodiments, the heavyhydrocarbons may be produced from another relatively permeable formationor any other formation containing heavy hydrocarbons, at the same siteor another site,

[1777] In some embodiments, the first section and the second section ofthe formation may be at different depths within the same formation. Forexample, the heavy hydrocarbons may be produced from a section having adepth between about 500 m and about 1500 m, a section having a depthbetween about 500 m and about 1200 m, or a section having a depthbetween about 500 m and about 800 m. At these depths, the heavyhydrocarbons may be somewhat mobile (and producible) due to a relativelyhigher natural temperature in the reservoir. The light hydrocarbons maybe produced from a section having a depth between about 10 m and about500 m, a section having a depth between about 10 m and about 400 m, or asection having a depth between about 10 m and about 250 m. At theseshallower depths, heavy hydrocarbons may not be readily produciblebecause of the lower natural temperatures at the shallower depths. Inaddition, the API gravity of heavy hydrocarbons may be lower atshallower depths due to increased water washing, loss of lighterhydrocarbons due to leaks in the seal of the formation, and/or bacterialdegradation. In other embodiments, heavy hydrocarbons and lighthydrocarbons are produced from first and second sections that are at asimilar depth below the surface. In another embodiment, the lighthydrocarbons and the heavy hydrocarbons are produced from differentformations. The different formations, however, may be located near eachother.

[1778] In an embodiment, heavy hydrocarbons are cold produced from aformation (e.g., a tar sands formation in the Faja (Venezuela)) atdepths between about 760 m and about 823 m. The produced hydrocarbonsmay have an API gravity of less than about 9°. Cold production of heavyhydrocarbons is generally defined as the production of heavyhydrocarbons without providing heat (or providing relatively littleheat) to the formation or the production well. In other embodiments, theheavy hydrocarbons may be produced by steam injection or a mixture ofsteam injection and cold production. The heavy hydrocarbons may be mixedwith a blending agent to transport the produced heavy hydrocarbonsthrough a pipeline. In one embodiment, the blending agent is naphtha.Naphtha may be produced in treatment facilities that are locatedremotely from the formation.

[1779] In other embodiments, the heavy hydrocarbons may be mixed with ablending agent produced from a shallower section of the formation usingan in situ conversion process. The shallower section may be at a depthless than about 400 m (e.g., less than about 150 m). The shallowersection of the formation may contain heavy hydrocarbons with an APIgravity of less than about 7°. The blending agent may include lighthydrocarbons produced by pyrolyzing at least some of the heavyhydrocarbons from the shallower section of the formation. The blendingagent may have an API gravity above about 35° (e.g., above about 40°).

[1780] In certain embodiments, a blending agent may be produced in afirst portion of a relatively permeable formation and injected (e.g.,into a production well) into a second portion of the relativelypermeable formation (or, in some embodiments, a second portion inanother relatively permeable formation). Heavy hydrocarbons may beproduced from the second portion (e.g., by cold production). Mixingbetween the blending agent may occur within the production well and/orwithin the second portion of the formation. The blending agent may beproduced through a production well in the first portion and pumped to aproduction well in the second portion. In some embodiments,non-hydrocarbon fluids (e.g., water or carbon dioxide), vapor-phasehydrocarbons, and/or other undesired fluids may be separated from theblending agent prior to mixing with heavy hydrocarbons.

[1781] Injecting the blending agent into a portion of a relativelypermeable formation may provide mixing of the blending agent and heavyhydrocarbons in the portion. The blending agent may be used to assist inthe production of heavy hydrocarbons from the formation. The blendingagent may reduce a viscosity of heavy hydrocarbons in the formation.Reducing the viscosity of heavy hydrocarbons in the formation may reducethe possibility of clogging or other problems associated with coldproducing heavy hydrocarbons. In some embodiments, the blending agentmay be at an elevated temperature and be used to provide at least someheat to the formation to increase the mobilization (i.e., reduce theviscosity) of heavy hydrocarbons within the formation. The elevatedtemperature of the blending agent may be a temperature proximate thetemperature at which the blending agent is produced minus some heatlosses during production and transport of the blending agent. In certainembodiments, the blending agent may be pumped through an insulatedpipeline to reduce heat losses during transport.

[1782] The blending agent may be mixed with the cold produced heavyhydrocarbons in a selected ratio to produce a third mixture with aselected API gravity. For example, the blending agent may be mixed withcold produced heavy hydrocarbons in a 1 to 2 ratio or a 1 to 4 ratio toproduce a third mixture with an API gravity greater than about 20°. Insome embodiments, other ratios of blending agent to heavy hydrocarbonsmay be selected as desired to produce a third mixture with one or moreselected properties. In certain embodiments, the third mixture may havean overall API gravity greater than about 25° or an API gravitysufficiently high such that the third mixture is transportable through aconduit or pipeline. In some embodiments, the third mixture ofhydrocarbons may have an API gravity between about 20° and about 45°. Inother embodiments, the blending agent may be mixed with cold producedheavy hydrocarbons to produce a third mixture with a selected viscosity,a selected stability, and/or a selected density.

[1783] The third mixture may be transported through a conduit, such as apipeline, between the formation and a treatment facility or refinery.The third mixture may be transported through a pipeline to anotherlocation for further transportation (e.g., the mixture can betransported to a facility at a river or a coast through the pipelinewhere the mixture can be further transported by tanker to a processingplant or refinery). Producing the blending agent at the formation site(i.e., producing the blending agent from the formation) may reduce atotal cost for producing hydrocarbons from the formation. In addition,producing the third hydrocarbon mixture at a formation site mayeliminate a need for a separate supply of light hydrocarbons and/orconstruction of a treatment facility at the site.

[1784] In an embodiment, a mixture of hydrocarbons may include about 20weight % light hydrocarbons (or blending agent) or greater (e.g., about50 weight % or about 80 weight % light hydrocarbons) and about 80 weight% heavy hydrocarbons or less (e.g., about 50 weight % or about 20 weight% heavy hydrocarbons). The weight percentage of light hydrocarbons andheavy hydrocarbons may vary depending on, for example, a weightdistribution (or API gravity) of light and heavy hydrocarbons, arelatively stability of the third mixture or a desired API gravity ofthe mixture. For example, in some embodiments, the weigh percentage oflight hydrocarbons in the mixture may be less than 50 weight % or lessthan 20 weight %. In certain embodiments, the weight percentage of lighthydrocarbons may be selected to blend the least amount of lighthydrocarbons with heavy hydrocarbons that produces a mixture with adesired density or viscosity. Reducing the viscosity of heavyhydrocarbons with a blending agent may make it easier to separate waterfrom the blended hydrocarbons.

[1785]FIG. 150 depicts a plan view of an embodiment of a relativelypermeable formation used to produce a first mixture that is blended witha second mixture. Relatively permeable formation 1702 may include firstsection 1704 and second section 1706. First section 1704 may be atdepths greater than, for example, about 800 m below a surface of theformation. Heavy hydrocarbons in first section 1704 may be producedthrough production well 512 placed in the first section. Heavyhydrocarbons in first section 1704 may be produced without heatingbecause of the depth of the first section. First section 1704 may bebelow a depth at which natural heating mobilizes heavy hydrocarbonswithin the first section. In some embodiments, at least some heat may beprovided to first section 1704 to mobilize fluids within the firstsection.

[1786] Second section 1706 may be heated using heat sources 508 placedin the second section. Heat sources 508 are depicted as substantiallyhorizontal heat sources in FIG. 150. Heat provided by heat sources 508may pyrolyze at least some hydrocarbons within second section 1706.Pyrolyzed fluids may be produced from second section 1706 throughproduction well 512. Production well 512 is depicted as a substantiallyvertical production well in FIG. 150.

[1787] In an embodiment, heavy hydrocarbons from first section 1704 areproduced in a first mixture through production well 512. Lighthydrocarbons (i.e., pyrolyzed hydrocarbons) may be produced in a secondmixture through production well 512. The first mixture and the secondmixture may be mixed to produce a third mixture in treatment facility516. The first and the second mixture may be mixed in a selected ratioto produce a desired third mixture. The third mixture may be transportedthrough pipeline 1708 to a production facility or a transportationfacility. The production facility or transportation facility may belocated remotely from treatment facility 516. In some embodiments, thethird mixture may be trucked or shipped to a production facility ortransportation facility. In certain embodiments, treatment facility 516may be a simple mixing station to combine the mixtures produced fromproduction well 512 and production well 512.

[1788] In certain embodiments, the blending agent produced from secondsection 1706 may be injected through production well 512 into firstsection 1704. A mixture of light hydrocarbons and heavy hydrocarbons maybe produced through production well 512 after mixing of the blendingagent and heavy hydrocarbons in first section 1704. In some embodiments,the blending agent may be produced by separating non-desirablecomponents (e.g., water) from a mixture produced from second section1706. The blending agent may be produced in treatment facility 516. Theblending agent may be pumped from treatment facility 516 throughproduction well 512 and into first section 1704.

[1789] FIGS. 151-157 depict results from an experiment. In theexperiment, blending agent 1710 produced by pyrolysis was mixed withAthabasca tar (heavy hydrocarbons 1712) in three blending mixtures ofdifferent ratios. First mixture 1714 included 80% blending agent 1710and 20% heavy hydrocarbons 1712. Second mixture 1716 included 50%blending agent 1710 and 50% heavy hydrocarbons 1712. Third mixture 1718included 20% blending agent 1710 and 80% heavy hydrocarbons 1712.Composition, physical properties, and asphaltene stability were measuredfor the blending agent, heavy hydrocarbons, and each of the mixtures.

[1790] TABLE 18 presents results of composition measurements of themixtures. SARA analysis determined composition on a topped oil basis.SARA analysis includes a combination of induced precipitation (forasphaltenes) and column chromatography. Whole oil basis compositionswere also determined. TABLE 18 Blend Ratio Topped oil basis (SARA) Wholeoil basis Blend 1712:1710 Sat Aro NSO Asph NSO Asph 1710  0:100 43.446.5 9.8 0.23 0.42 0.01 1714 20:80 20.6 49.4 20.6 9.30 4.91 2.21 171650:50 15.3 51.5 20.1 13.0 10.7 6.91 1718 80:20 14.4 51.5 20.8 13.1 16.410.3 1712 100:0  12.5 52.8 20.2 14.5 18.4 13.2

[1791]FIG. 151 depicts asphaltene content (on a whole oil basis) in theblend versus percent blending agent in the mixture for each of the threemixtures (1714, 1716, and 1718), blending agent 1710, and heavyhydrocarbons 1712. As shown in FIG. 151, asphaltene content on a wholeoil basis varies linearly with the percentage of blending agent 1710 inthe mixture.

[1792]FIG. 152 depicts SARA results (saturate/aromatic ratio versusasphaltene/resin ratio) for each of the blends (1710, 1714, 1716, 1718,and 1712). The line in FIG. 152 represents the differentiation betweenstable mixtures and unstable mixtures based on SARA results. The toppingprocedure used for SARA removed a greater proportion of the contributionof blending agent 1710 (as compared to whole oil analysis) and resultedin the non-linear distribution in FIG. 152. First mixture 1714, secondmixture 1716, and third mixture 1718 plotted closer to heavyhydrocarbons 1712 than blending agent 1710. In addition, second mixture1716 and third mixture 1718 plotted relatively closely. All blends(1710, 1714, 1716, 1718, and 1712) plotted in a region of marginalstability.

[1793] Blending agent 1710 included very little asphaltene (0.01% byweight, whole oil basis). Heavy hydrocarbons 1712 included about 13.2%by weight (whole oil basis) with the amount of asphaltenes in themixtures (1714, 1716, and 1718) varying between 2.2% by weight and 10.3%by weight on a whole oil basis. Other indicators of the gross oilproperties is the ratio between saturates and aromatics and the ratiobetween asphaltenes and resins. The asphaltene/resin ratio was lowestfor first mixture 1714, which has the largest percentage of blendingagent 1710. Second mixture 1716 and third mixture 1718 had relativelysimilar asphaltene/resin ratios indicating that the majority of resinsin the mixtures are due to contribution from heavy hydrocarbons 1712.The saturate/aromatic ratio was relatively similar for each of themixtures.

[1794] Density and viscosity of the mixtures were measured at threetemperatures: 4.4° C. (40° F.), 21° C. (70° F.), and 32° C. (90° F.).The density and API gravity of the mixtures were also determined at 15°C. (60° F.) and used to calculate API gravities at other temperatures.In addition, a Floc Point Analyzer (FPA) value was determined for eachof the three blended mixtures (1714, 1716, and 1718). FPA is determinedby n-heptane titration. The floc point is detected with a near infraredlaser. The light source is blocked by asphaltenes precipitating out ofsolution. The FPA test was calibrated with a set of known problem andnon-problem mixtures. Generally, FPA values less than 2.5 are consideredunstable, greater than 3.0 are considered stable, and 2.5-3.0 areconsidered marginal. TABLE 19 presents values for FPA, density,viscosity, and API gravity for the three blended mixtures at fourtemperatures. TABLE 19 Temperature: 15° C. 4.4° C. 21° C. 32° C. Spec.Density Density Visc. Density Visc. Density Visc. Blend FPA Grav. (g/cc)API (g/cc) (cs) API (g/cc) (cs) API (g/cc) (cs) API 1714 1.5 0.8450.8443 35.9 0.8535 4.20 34.12 0.8405 2.95 36.7 0.8324 2.39 39.3 1716 2.20.909 0.9086 24.1 0.9177 53.9 22.54 0.9052 25.6 24.7 0.8974 16.2 26.01718 2.8 0.976 0.9751 13.5 0.9839 5934 12.18 0.9717 1267 14.0 0.9643531.6 15.1

[1795] FPA tests showed that the mixtures containing lower amounts ofheavy hydrocarbons were less stable. The lower stability was likely dueto the proportion of aliphatic components already in these mixtures,which reduces asphaltene solubility. First mixture 1714 was the leaststable with a FPA value of 1.5, indicating instability with respect toasphaltene precipitation. FIG. 153 illustrates near infraredtransmittance versus volume (ml) of n-heptane added to first mixture1714. The peak in the plot for first mixture 1714 illustrates thatprecipitation of asphaltenes occurs rapidly with the addition ofn-heptane.

[1796] Second mixture 1716 exhibited different behavior. Second mixture1716 had a FPA value of 2.2 indicating instability with respect toasphaltene precipitation. FIG. 154 illustrates near infraredtransmittance versus volume (ml) of n-heptane added to second mixture1716. Two distinct peaks are seen in FIG. 154 indicating thatasphaltenes were precipitated, re-dissolved, and then re-precipitatedwith continuous addition of n-heptane.

[1797]FIG. 155 illustrates near infrared transmittance versus volume(ml) of n-heptane added to third mixture 1718. Third mixture 1718 showedsimilar behavior to second mixture 1716 as shown in FIG. 154 and FIG.155. The first peak in FIG. 155, however, was less pronounced than thefirst peak in FIG. 154. The FPA value of 2.8 found for third mixture1718 indicates marginal stability for the third mixture. Slowhomogenization, associated with a high viscosity of the sample mixtures,is most likely responsible for the appearance of double peaks in FIGS.154 and 155.

[1798] Each of the mixtures (1714, 1716, and 1718) showed relativelysimilar changes in density with increasing temperature (as shown in FIG.156). API values increased correspondingly with decreasing density.Viscosity changes, however, varied between each of the mixtures.

[1799] First mixture 1714 was the least affected by temperature withviscosity values at 21° C. and 32° C. determined to be about 70% andabout 57% of that at 4.4° C., respectively. Second mixture 1716 hadviscosity values that decreased to values (of that at 4.4° C.) of about48% at 21° C. and about 30% at 32° C. Third mixture 1718 was the mostaffected by temperature with viscosity values of about 21% and about 9%at 21° C. and 32° C., respectively. Viscosity changes are approximatelylinear on a logarithmic plot of viscosity versus temperature as shown inFIG. 157.

[1800] Typically, a majority of relatively permeable formations arewater-wet. A substantial majority of flow within the formation may occurwhile the formation remains water-wet (increased temperatures in theformation has not resulted in the vaporization of water in theformation). The formation being water-wet may help the efficiency ofgravity-produced flow in the formation during early stages ofproduction. The formation may become more oil-wet as water evaporatesand/or as asphaltene is precipitated (asphaltene precipitation maydepend on oil composition, pressure and temperature, and/or CO₂ level).Later stages of production may occur when the reservoir is oil-wet.Oil-wet production may increase the efficiency of film drainage duringthe later stages of production.

[1801] In some embodiments, permeability of a relatively permeableformation may be improved upon heating of the relatively permeableformation. Some relatively permeable formations include clays such askaolinite between the grains. The clays may reduce permeability in theformation. These clays may dissolve at temperatures approaching andabove about 250° C. in the presence of steam. The steam may be generatedby water evaporation in the formation. Dissolving the clays willincrease the permeability of the formation. Permeability may also beincreased due to reduction in effective stress of the formation as fluidpressure increases in the formation during heating. The fluid pressuremay increase in the pore spaces of the formation during heating. Thermalexpansion of the fluids may produce dilatancy effects in the formation.“Dilatancy” is the tendency of rocks to expand along minute fracturesimmediately prior to failure. Dilatancy may increase permeability in theformation.

[1802] In some embodiments, the formation may be treated to provide apathway for vertical drainage of fluids if no such pathway exists. Forexample, the formation may be fractured hydraulically or by othertechniques.

[1803] Toward the end of production, oil quality may also improve ascompared to initial oil quality. Carbon dioxide produced in theformation may cause non-cracking related upgrading (e.g., by asphalteneprecipitation or viscosity reduction) of fluids within the formation.

[1804] In some embodiments, injection of carbon dioxide can be used tosequester carbon dioxide within the formation. As production from theformation is slowed and/or halted, carbon dioxide may be sequestered inthe formation at relatively high pressures. This may reduce carbon taxesassociated with a production process and/or create environmentalemissions credit.

[1805] In certain embodiments, evaporation of water within the formationmay increase pressure in the formation due to production of steam. Theproduced steam may increase flow of mobilized fluids within theformation.

[1806] In some embodiments, a relatively permeable formation may includetar mats. Tar mats may form by a variety of methods. One possibility fortar mat formation is through deasphalting. Deasphalting may includecompositional gravity segregation as well as a destabilization of an oildue to gas addition. Gas addition may be provided by migration fromadjacent areas and/or by gas formation within the formation. Anotherpossibility for tar mat formation may be by biodegradation and/or waterwashing. In addition, there is the possibility of in situ maturation,with lighter oil and pyrobitumen forming from a heavier precursor.Another formation possibility is asphaltenic precipitation due topressure decline during uplift of a formation. The chemistry of a tarmat may be highly asphaltenic (i.e., complex hydrocarbons with highmolecular weights). Reservoirs with basal or lateral tar mats existworldwide.

[1807] In certain embodiments, a tar mat may inhibit oil production bywater drive. In such embodiments, heater wells may be used to heat a tarmat zone sufficiently to remove bitumen from the formation or lower theoil viscosity in the tar mat. This process may significantly improvepermeability and flow characteristics within the tar mat zone, thusallowing enhanced production due to a natural water drive or some otherdrive mechanism (e.g., water or steam injection).

[1808] An in situ conversion process may be used to produce hydrocarbonsfrom a relatively low permeability formation. Hydrocarbon material inthe low permeability formation may be heavy hydrocarbons. Hydrocarbonsin a selected section of the formation may be pyrolyzed by heat fromheat sources. Heat provided by the heat sources may allow for vaporphase transport to production wells in the formation.

[1809] In addition to allowing for vapor phase transport through theselected section of formation, heating the formation may also increasethe average permeability of at least a portion of the selected section.The increase in temperature of the formation may create thermalfractures in the formation. The thermal fractures may propagate betweenheat sources, further increasing the permeability in a portion of aselected section of the formation. During heating of the formation topyrolysis temperatures, water in the selected section may vaporize.Vaporization may generate localized areas of very high pressure thatcause fracturing of the selected formation. In some formations, theformation and/or heavy hydrocarbons in the formation may absorb aportion of the energy caused by thermal expansion and/or by vaporizationpressure change to limit increasing permeability.

[1810] In an in situ conversion process embodiment, the pressure in atleast a portion of the relatively low permeability formation may becontrolled to maintain a composition of produced formation fluids withina desired range. The composition of the produced formation fluids may bemonitored. The pressure may be controlled by a back pressure valvelocated proximate where the formation fluids are produced. A desiredoperating pressure of a production well to produce a desired compositionmay be determined from experimental data for the relationship betweenpressure and the composition of pyrolysis products of the heavyhydrocarbons in the formation.

[1811]FIG. 158 is a view of an embodiment of a heat source andproduction well pattern for heating heavy hydrocarbons in a relativelylow permeability formation. Heat sources 508A, 508B, and 508C may bearranged in a triangular pattern with the heat sources at the apices ofthe triangular grid. Production well 512 may be located proximate thecenter of the triangular grid. In other pattern embodiments, aproduction well may be placed at any location in the grid pattern. Heatsources may be arranged in patterns other than the triangular patternshown in FIG. 158. For example, wells may be arranged in squarepatterns. Heat sources 508A, 508B, and 508C may heat a portion of theformation to a temperature that allows for pyrolysis of heavyhydrocarbons in the formation. Pyrolyzation fluids produced by pyrolysismay flow toward the production well, as indicated by the arrows, andformation fluids may be produced through production well 512.

[1812] In some in situ conversion process embodiments for treating lowpermeability formations, average distances between heat sourceseffective to pyrolyze heavy hydrocarbons in the formation may be betweenabout 5 m and about 8 m. In some embodiments, a smaller average distancemay be needed. In some in situ conversion process embodiments fortreating low permeability formations, average distance between heatsources may be between about 2 m and about 5 m.

[1813]FIG. 159 is a view of an embodiment of a heat source pattern forheating heavy hydrocarbons in a portion of a hydrocarbon containingformation of relatively low permeability and producing fluids from oneor more heater wells. Heat sources 508 may be arranged in a triangularpattern. The heat sources may provide heat to pyrolyze some or all ofthe fluid in the formation. Fluids may be produced through one or moreof the heat sources.

[1814] An embodiment for treating hydrocarbons in a relatively lowpermeability formation may include heating the formation to create atleast two zones within the formation such that the zones have differentaverage temperatures. Heat sources may heat a first section of theformation to create a pyrolysis zone. Heat sources may heat a secondsection to an average temperature that is less than a pyrolysistemperature to create a low viscosity zone.

[1815] The decrease in viscosity of the heavy hydrocarbons in theselected second section may be sufficient to produce mobilized fluidswithin the selected second section. The mobilized fluids may flow intothe pyrolysis zone of the first section. For example, increasing thetemperature of the heavy hydrocarbons in the formation to between about200° C. and about 250° C. may decrease the viscosity of the heavyhydrocarbons sufficiently for the heavy hydrocarbons to flow through theformation. In another embodiment, increasing the temperature of thefluid to between about 180° C. and about 200° C. may also be sufficientto mobilize the heavy hydrocarbons. For example, the viscosity of heavyhydrocarbons in a formation at 200° C. may be about 50 centipoise toabout 200 centipoise. Production wells in the first section may create alow pressure zone that facilitates fluid flow from the second sectioninto the first section.

[1816] Heating may create thermal fractures that propagate between heatsources in both the selected first section and the selected secondsection. The thermal fractures may substantially increase thepermeability of the formation and may facilitate the flow of mobilizedfluids from the low viscosity zone to the pyrolysis zone. In oneembodiment, a vertical hydraulic fracture may be created in theformation to further increase permeability. The presence of a hydraulicfracture may also be desirable since heavy hydrocarbons that collect inthe hydraulic fracture may have an increased residence time in thepyrolysis zone. The increased residence time may result in increasedpyrolysis of the heavy hydrocarbons in the pyrolysis zone.

[1817] In addition, the pressure in the low viscosity zone may increasedue to thermal expansion of the formation and evaporation of entrainedwater in the formation to form steam. For example, pressures in the lowviscosity zone may range from about 10 bars absolute to an overburdenpressure. In some process embodiments, the pressure may range from about15 bars absolute to about 50 bars absolute. The value of the pressuremay depend upon factors such as, but not limited to, the degree ofthermal fracturing, the amount of water in the formation, and materialproperties of the formation. The pressure in the pyrolysis zone may besubstantially lower than the pressure in the low viscosity zone becauseof the higher permeability of the pyrolysis zone. The higher temperaturein the pyrolysis zone compared to the low viscosity zone may cause ahigher degree of thermal fracturing, and thus a greater permeability.For example, pyrolysis zone pressures may range from about 3.5 barsabsolute to about 10 bars absolute. In some embodiments, pyrolysis zonepressures may range from about 10 bars absolute to about 15 barsabsolute.

[1818] The pressure differential between the pyrolysis zone and the lowviscosity zone may force some mobilized fluids to flow from the lowviscosity zone into the pyrolysis zone. Heavy hydrocarbons in thepyrolysis zone may be upgraded by pyrolysis into pyrolyzation fluids.Pyrolyzation fluids may be produced from the formation through aproduction well or production wells. A production well or productionwells may be designed to remove liquids, vapor or a combination ofliquid and vapor from the formation.

[1819] In an in situ conversion process embodiment, the concentration(or density) of heat sources in the pyrolysis zone may be greater thanthe concentration of heat sources in the low viscosity zone. Theincreased concentration of heat sources in the pyrolysis zone mayestablish and maintain a uniform pyrolysis temperature in the pyrolysiszone. Using a lower concentration of heat sources in the low viscosityzone may be more efficient and economical due to the lower temperaturerequired in the low viscosity zone. In one process embodiment, anaverage distance between heat sources for heating the first selectedsection may be between about 5 m and about 10 m. Alternatively, anaverage distance may be between about 2 m and about 5 m. In someembodiments, an average distance between heat sources for heating thesecond selected section may be between about 5 m and about 20 m.

[1820] In an in situ conversion process embodiment, the pyrolysis zoneand one or more low viscosity zones may be heated sequentially overtime. Heat sources may heat the first selected section until an averagetemperature of the pyrolysis zone reaches a desired pyrolysistemperature. Subsequently, heat sources may heat one or more lowviscosity zones of the selected second section that may be nearest thepyrolysis zone until such low viscosity zones reach a desired averagetemperature. Heating low viscosity zones of the selected second sectionfarther away from the pyrolysis zone may continue in a like manner.

[1821] In an in situ conversion process embodiment, heat may be providedto a formation to create a first volume of formation at a pyrolysistemperature (pyrolysis zone) and an adjacent volume of formation below apyrolysis temperature (low viscosity zone). One or more planar lowviscosity zones may be created with symmetry about the pyrolysis zone.In an in situ conversion process embodiment, the pyrolysis zone may besurrounded by an annular low viscosity zone. In some embodiments,portions of the pyrolysis zone that no longer produce formation fluidsof a desired quality and/or quantity are allowed to cool while a leadingedge or leading edges (or a circumference) of pyrolysis zone ismaintained at pyrolysis temperatures. Formation fluids may be producedthrough a production well or production wells. The production well orproduction wells may be located in the pyrolysis zone and/or in aproduced portion of the formation that is no longer maintained atpyrolysis temperatures.

[1822]FIG. 160 is a view of an embodiment of a heat source andproduction well pattern illustrating a pyrolysis zone and a lowviscosity zone. Heat sources 508A along plane 1720A and plane 1720B mayheat planar region 1722 to create a pyrolysis zone. Heating may createthermal fractures 1724 in the pyrolysis zone. Heating with heat sources508B in planes 1720C, 1720D, 1720E, and 1720F may create a low viscosityzone with an increased permeability due to thermal fractures. Pressuredifferential between the low viscosity zone and the pyrolysis zone mayforce mobilized fluid from the low viscosity zone into the pyrolysiszone. The permeability created by thermal fractures 1724 may besufficiently high to create a substantially uniform pyrolysis zone.Pyrolyzation fluids may be produced through production well 512.

[1823] In an in situ conversion process embodiment, a pyrolysis zoneand/or low viscosity zone may move as time spent processing theformation advances. In an embodiment, the, heat sources nearest thepyrolysis zone may be activated first. For example, heat sources 508Abetween plane 1720A and plane 1720B of FIG. 160 may be activated first.A substantially uniform temperature may be established in the pyrolysiszone after a period of time. Mobilized fluids that flow through thepyrolysis zone may undergo pyrolysis and vaporize. Once the pyrolysiszone is established, heat sources in the low viscosity zone (e.g., heatsources 508B adjacent to plane 1720A and in plane 1720E) nearest thepyrolysis zone may be turned on and/or up to establish a low viscosityzone. A larger low viscosity zone may be developed by repeatedlyactivating heat sources (e.g., heat sources 508B in plane 1720E and heatsources in plane 1720F) farther away from the pyrolysis zone. Heatsources 508B in plane 1720C and plane 1720D may also be activated atappropriate times.

[1824]FIG. 161 depicts an aerial view of a pattern for treating arelatively low permeability formation. Heat sources may create pyrolysiszones 1726. Regions 1728A, 1728B, and 1728C may include heat sourcesthat apply heat to create a low viscosity zone. Production wells 512 maybe disposed in regions where pyrolysis occurs. Production wells 512 mayremove pyrolyzation fluids from the formation. In one embodiment, alength of pyrolysis zones 1726 may be between about 75 m and about 300m. In another embodiment, a length of the pyrolysis zones may be betweenabout 100 m and about 125 m. In an embodiment, an average distancebetween production wells in the same plane may be between about 100 mand about 150 m. Shorter or longer production zones may be establishedto correspond to formation conditions. In one embodiment, a distancebetween plane 1730A and plane 1730B may be between about 40 m and about80 m. In some embodiments, more than one production well may be disposedin a region where pyrolysis occurs. Plane 1730A and plane 1730B may besubstantially parallel. The formation may include additional planarvertical pyrolysis zones that may be substantially parallel to eachother. Hot fluids may be provided into vertical planar regions such thatin situ pyrolysis of heavy hydrocarbons may occur. Pyrolyzation fluidsmay be removed by production wells disposed in the vertical planarregions.

[1825] An embodiment of a planar pyrolysis zone may include a verticalhydraulic fracture created by hydraulically fracturing through aproduction well in the formation. The formation may include heat sourceslocated substantially parallel to the vertical hydraulic fracture in theformation. Heat sources in a planar region adjacent to the fracture mayprovide heat sufficient to pyrolyze at least some or all of the heavyhydrocarbons in a pyrolysis zone. Heat sources outside the planar regionmay heat the formation to a temperature sufficient to decrease theviscosity of the fluids in a low viscosity zone.

[1826]FIG. 162 is a view of an embodiment for treating heavyhydrocarbons in at least a portion of a hydrocarbon containing formationof relatively low permeability. Fracture 1732 may be created fromwellbore of production well 512. In an embodiment, the width of fracture1732 generated by hydraulic fracturing may be between about 0.3 cm andabout 1 cm. In other embodiments, the width of fracture 1732 may bebetween about 1 cm and about 3 cm. The pyrolysis zone may be formed in aplanar region on either side of the vertical hydraulic fracture byheating the planar region to an average temperature within a pyrolysistemperature range with heat sources 508A in plane 1720A and plane 1720B.Creation of a low viscosity zone on both sides of the pyrolysis zone,above plane 1720A and below plane 1720B, may be accomplished by heatsources outside the pyrolysis zone. For example, heat sources 508B inplanes 1720C, 1720D, 1720E, and 1720F may heat the low viscosity zone toa temperature sufficient to lower the viscosity of heavy hydrocarbons inthe formation. Mobilized fluids in the low viscosity zone may flow tothe pyrolysis zone due to the pressure differential between the lowviscosity zone and the pyrolysis zone and the increased permeabilityfrom thermal fractures.

[1827]FIG. 163 is a view of an embodiment for treating a relatively lowpermeability formation. FIG. 163 illustrates a formation with twofractures 1732A, 1732B along plane 1720A and two fractures 1732C, 1732Dalong plane 1720B. Each fracture may be produced from wellbores ofproduction wells 512. Plane 1720A and plane 1720B may be substantiallyparallel. The length of a fracture created by hydraulic fracturing inrelatively low permeability formations may be between about 75 m andabout 100 m. In some embodiments, the vertical hydraulic fracture may bebetween about 100 m and about 125 m. Vertical hydraulic fractures maypropagate substantially equal distances along a plane from a productionwell. The distance between production wells along the same plane may bebetween about 100 m and about 150 m to inhibit fractures from joiningtogether. As the distance between fractures on different planesincreases, for example the distance between plane 1720A and plane 1720B,the flow of mobilized fluids farthest from either fracture may decrease.A distance between fractures on different planes that may be economicaland effective for the transport of mobilized fluids to the pyrolysiszone may be about 40 m to about 80 m.

[1828] Plane 1720C and plane 1720D may include heat sources that mayprovide heat sufficient to create a pyrolysis zone between the planes.Plane 1720E and plane 1720F may include heat sources that create apyrolysis zone between the planes. Heat sources in regions 1728A, 1728B,1728C, and 1728D may provide heat that may create low viscosity zones.Mobilized fluids in regions 1728A, 1728B, 1728C, and 1728D may flow in adirection toward the closest fracture in the formation. Mobilized fluidsentering the pyrolysis zone may be pyrolyzed. Pyrolyzation fluids may beproduced from production wells 512.

[1829] In one in situ conversion process embodiment, heat may beprovided to a relatively low permeability formation to create apyrolysis zone and a low viscosity zone around a production well. Fluidsmay be pyrolyzed in the pyrolysis zone. Pyrolyzation fluids may beproduced from the production well in the pyrolysis zone. Heat sourcesmay be located around a production well in a pattern. Heat sourcesclosest to a production well may heat portions of the formation adjacentto the production well to a pyrolysis temperature. Additional heatersfarther from the production well may heat the formation to create a lowviscosity zone. Mobilized fluid in the low viscosity zone may flow tothe pyrolysis zone due to the pressure differential between the lowviscosity zone and the pyrolysis zone. An increased permeability due tothermal fracturing of the formation may facilitate flow of hydrocarbonsto the pyrolysis zone and production well.

[1830] Several patterns of heat sources arranged in rings aroundproduction wells may be utilized to create a pyrolysis region around aproduction well and a low viscosity zone in a hydrocarbon containingformation. Various pattern embodiments are shown in FIGS. 164-177.Although the patterns are discussed in the context of heavyhydrocarbons, it is to be understood that any of the patterns shown inFIGS. 164-177 may be used for other hydrocarbon containing formations(e.g., for coal, oil shale, etc.).

[1831]FIG. 164 illustrates an embodiment of a pattern of heat sources508 that may create a pyrolysis zone and low viscosity zone aroundproduction well 512. Production well 512 may be surrounded by rings1734, 1736, and 1738 of heat sources 508. Heat sources 508 in ring 1734may heat the formation to create pyrolysis zone 1726. Heat sources 508in rings 1736 and 1738 outside pyrolysis zone 1726 may heat theformation to create a low viscosity zone. The viscosity of a portion ofthe hydrocarbons in the low viscosity zone may be reduced sufficientlyto allow the hydrocarbons to flow inward from the low viscosity zone topyrolysis zone 1726. Fluids may be produced through production well 512.In some embodiments, an average distance between heat sources may bebetween about 2 m and about 10 m. In other embodiments, the averagedistance between heat sources may be between about 10 m and about 20 m.

[1832] Pyrolysis zones and low viscosity zones in a formation may becreated sequentially. Heat sources 508 nearest production well 512 maybe activated first, for example, heat sources 508 in ring 1734. Asubstantially uniform temperature pyrolysis zone may be establishedafter a period of time. Fluids that flow through the pyrolysis zone mayundergo pyrolysis and/or vaporization. Once the pyrolysis zone isestablished, heat sources 508 in the low viscosity zone near thepyrolysis zone (e.g., heat sources 508 in ring 1736) may be activated toprovide heat to a portion of a low viscosity zone. Fluid may flow inwardtowards production well 512 due to a pressure differential between thelow viscosity zone and the pyrolysis zone, as indicated by the arrows. Alarger low viscosity zone may be developed by repeatedly activating heatsources farther away from production well 512 (e.g., heat sources 508 inring 1738).

[1833] Production wells 512 and heat sources 508 may be located at theapices of a triangular grid, as depicted in FIG. 165. The triangulargrid for heat sources 508 may be an equilateral triangular grid withsides of length s. Production wells 512 may be spaced at a distance ofabout 1.732(s). Each production well 512 may be disposed at a center ofring 1740 of heat sources 508 in a hexagonal pattern. Each heat source508 may provide substantially equal amounts of heat to three productionwells. Therefore, each ring 1740 of six heat sources 508 may contributeapproximately two equivalent heat sources per production well 512.

[1834]FIG. 166 illustrates a pattern of production wells 512 with aninner hexagonal ring 1740 and an outer hexagonal ring 1742 of heatsources 508. In this pattern, production wells 512 may be spaced at adistance of about 2(1.732)s, where s is the distance between heatsources 508. Heat sources 508 may be located at all other gridpositions. This pattern may result in a ratio of equivalent heat sourcesto production wells that may approach 11:1 (i.e., 6 equivalent heatsources for ring 1740; (½)(6) or 3 equivalent heat sources for the 6heat sources of ring 1742 between apices of the hexagonal pattern; and(⅓)(6) or 2 equivalent heat sources for the 6 heat sources of ring 1742at the apices of the hexagonal pattern).

[1835]FIG. 167 illustrates three rings of heat sources 508 surroundingproduction well 512. Production well 512 may be surrounded by ring 1740of six heat sources 508. Second hexagonally shaped ring 1742 of twelveheat sources 508 may surround ring 1740. Third ring 1744 of heat sources508 may include twelve heat sources that may provide substantially equalamounts of heat to two production wells and six heat sources that mayprovide substantially equal amounts of heat to three production wells.Therefore, a total of eight equivalent heat sources may be disposed onthird ring 1744. Production well 512 may be provided heat from anequivalent of about twenty-six heat sources. FIG. 168 illustrates aneven larger pattern that may have a greater spacing between productionwells 512.

[1836]FIGS. 169, 170, 171, and 172 illustrate embodiments in which bothproduction wells and heat sources are located at the apices of atriangular grid. In FIG. 169, a triangular grid with a spacing of sbetween adjacent heat sources may have production wells 512 spaced at adistance of 2s. A hexagonal pattern may include one ring 1740 of sixheat sources 508. Each heat source 508 may provide substantially equalamounts of heat to two production wells 512. Therefore, each ring 1740of six heat sources 508 contributes approximately three equivalent heatsources per production well 512.

[1837]FIG. 170 illustrates a pattern of production wells 512 with innerhexagonal ring 1740A and outer hexagonal ring 1740B. Production wells512 may be spaced at a distance of 3s. Heat sources 508 may be locatedat apices of hexagonal ring 1740A and hexagonal ring 1740B. Hexagonalring 1740A and hexagonal ring 1740B may include six heat sources each.The pattern in FIG. 170 may result in a ratio of heat sources 508 toproduction well 512 of about eight.

[1838]FIG. 171 illustrates a pattern of production wells 512 also withtwo hexagonal rings of heat sources surrounding each production well.Production well 512 may be surrounded by ring 1740 of six heat sources508. Production wells 512 may be spaced at a distance of 4s. Secondhexagonal ring 1742 may surround ring 1740. Second hexagonal ring 1742may include twelve heat sources 508. This pattern may result in a ratioof heat sources 508 to production wells 512 that may approach fifteen.

[1839]FIG. 172 illustrates a pattern of heat sources 508 with threerings of heat sources 508 surrounding each production well 512.Production wells 512 may be surrounded by ring 1740 of six heat sources508. Second ring 1742 of twelve heat sources 508 may surround ring 1740.Third ring 1744 of heat sources 508 may surround second ring 1742. Thirdring 1744 may include 6 equivalent heat sources. This pattern may resultin a ratio of heat sources 508 to production wells 512 that is about24:1.

[1840]FIGS. 173, 174, 175, and 176 illustrate patterns in which theproduction well may be disposed at a center of a triangular grid suchthat the production well may be equidistant from the apices of thetriangular grid. In FIG. 173, the triangular grid of heater wells with aspacing of s between adjacent heat sources may include production wells512 spaced at a distance of s. Each production well 512 may besurrounded by ring 1746 of three heat sources 508. Each heat source 508may provide substantially equal amounts of heat to three productionwells 512. Therefore, each ring 1746 of three heat sources 508 maycontribute one equivalent heat source per production well 512.

[1841]FIG. 174 illustrates a pattern of production wells 512 with innertriangular ring 1746 and outer hexagonal ring 1748. In this pattern,production wells 512 may be spaced at a distance of 2s. Heat sources 508may be located at apices of inner triangular ring 1746 and outerhexagonal ring 1748. Inner triangular ring 1746 may contribute threeequivalent heat sources per production well 512. Outer hexagonal ring1748 containing three heater wells may contribute one equivalent heatsource per production well 512. Thus, a total of four equivalent heatsources may provide heat to production well 512.

[1842]FIG. 175 illustrates a pattern of production wells with one innertriangular ring of heat sources surrounding each production well and oneirregular hexagonal outer ring. Production wells 512 may be surroundedby ring 1746 of three heat sources 508. Production wells 512 may bespaced at a distance of 3s, where s is the distance between adjacentheat sources. Irregular hexagonal ring 1750 of nine heat sources 508 maysurround ring 1746. This pattern may result in a ratio of heat sources508 to production wells 512 of about 9:1.

[1843]FIG. 176 illustrates triangular patterns of heat sources withthree rings of heat sources surrounding each production well. Productionwells 512 may be surrounded by ring 1746 of three heat sources 508.Irregular hexagon pattern 1750 of nine heat sources 508 may surroundring 1746. Third set 1752 of heat sources 508 may surround irregularhexagonal pattern 1750. Third set 1752 may contribute four equivalentheat sources to production well 512. A ratio of equivalent heat sourcesto production well 512 may be sixteen.

[1844]FIG. 177 depicts an embodiment of a pattern of heat sources 508arranged in a triangular pattern. Production well 512 may be surroundedby triangles 1746A, 1746B, and 1746C of heat sources 508. Heat sources508 in triangles 1746A, 1746B, and 1746C may provide heat to theformation. The provided heat may raise an average temperature of theformation to a pyrolysis temperature. Pyrolyzation fluids may flow toproduction well 512. Formation fluids may be produced in production well512.

[1845]FIG. 178 illustrates an example of a square pattern of heatsources and production wells 512. The heat sources are disposed atvertices of squares 1752. Production well 512 is placed in a center ofevery third square in both x- and y-directions. Midlines 1754 are formedequidistant to two production wells 512, and perpendicular to a lineconnecting such production wells. Intersections of midlines 1754 atvertices 1756 form unit cell 1758. Heat sources 508A are completelywithin unit cell 1758. Heat sources 508B and heat sources 508C are onlypartially within unit cell 1758. Only the one-half fraction of heatsources 508B and the one-quarter fraction of heat sources 508C withinunit cell 1758 provide heat within unit cell 1758. The fraction of heatsources outside of unit cell 1758 may provide heat to other unit cells.

[1846] The total number of heat sources attributable to unit cell 1758may be determined by the following method:

[1847] (a) 4 heat sources 508A inside unit cell 1758 are counted as oneheat source each;

[1848] (b) 8 heat sources 508B on midlines 1754 are counted as one-halfheat source each; and

[1849] (c) 4 heat sources 508C at vertices 1756 are counted asone-quarter heat source each.

[1850] The total number of heat sources is determined from adding theheat sources counted by (a) 4, (b) 8/2=4, and (c) 4/4=1, for a totalnumber of 9 heat sources in unit cell 1758. Therefore, a ratio of heatsources to production wells 512 is determined as 9:1 for the patternillustrated in FIG. 178.

[1851]FIG. 179 illustrates an example of another pattern of heat sources508 and production wells 512. Midlines 1754 are formed equidistant fromtwo production wells 512, and perpendicular to a line connecting suchproduction wells. Unit cell 1758 is determined by intersection ofmidlines 1754 at vertices 1756. Twelve heat sources are counted in unitcell 1758, of which six are whole sources of heat, and six are one-thirdsources of heat (with the other two-thirds of heat from such six wellsgoing to other patterns). Thus, a ratio of heat sources to productionwells 512 is determined as 8:1 for the pattern illustrated in FIG. 179.

[1852]FIG. 180 illustrates an embodiment of triangular pattern 1760 ofheat sources 508. FIG. 181 illustrates an embodiment of square pattern1762 of heat sources 508. FIG. 182 illustrates an embodiment ofhexagonal pattern 1764 of heat sources 508. FIG. 183 illustrates anembodiment of 12:1 pattern 1766 of heat sources 508. A temperaturedistribution for all patterns may be determined by an analytical method.The analytical method may be simplified by analyzing only temperaturefields within “confined” patterns (e.g., hexagons), i.e., completelysurrounded by others. In addition, the temperature field may beestimated to be a superposition of analytical solutions corresponding toa single heat source.

[1853]FIG. 184 illustrates a schematic diagram of an embodiment oftreatment facilities 516 that may treat a formation fluid. The formationfluid may be produced though a production well. Treatment facilities 516may include separator 1768. Separator 1768 may receive formation fluidproduced from a hydrocarbon containing formation during an in situconversion process. Separator 1768 may separate the formation fluid intogas stream 1770, liquid hydrocarbon condensate stream 1772, and waterstream 1774.

[1854] Water stream 1774 may flow from separator 1768 to a portion of aformation, to a containment system, or to a processing unit. Forexample, water stream 1774 may flow from separator 1768 to an ammoniaproduction unit. Ammonia produced in the ammonia production unit mayflow to an ammonium sulfate unit. The ammonium sulfate unit may combinethe ammonia with H₂SO₄ or SO₂/SO₃ to produce ammonium sulfate. Inaddition, ammonia produced in the ammonia production unit may flow to aurea production unit. The urea production unit may combine carbondioxide with the ammonia to produce urea.

[1855] Gas stream 1770 may flow through a conduit from separator 1768 togas treatment unit 1796. The gas treatment unit may separate variouscomponents of gas stream 1770. For example, the gas treatment unit mayseparate gas stream 1770 into carbon dioxide stream 1776, hydrogensulfide stream 1778, hydrogen stream 1780, and stream 1782 that mayinclude, but is not limited to, methane, ethane, propane, butanes(including n-butane or isobutane), pentane, ethene, propene, butene,pentene, water, or combinations thereof.

[1856] The carbon dioxide stream may flow through a conduit to aformation, to a containment system, to a disposal unit, and/or toanother processing unit. In addition, the hydrogen sulfide stream mayalso flow through a conduit to a containment system and/or to anotherprocessing unit. For example, the hydrogen sulfide stream may beconverted into elemental sulfur in a Claus process unit. The gastreatment unit may separate gas stream 1770 into stream 1784. Stream1784 may include heavier hydrocarbon components from gas stream 1770.Heavier hydrocarbon components may include, for example, hydrocarbonshaving a carbon number of greater than about 5. Heavier hydrocarboncomponents in stream 1784 may be provided to liquid hydrocarboncondensate stream 1772.

[1857] Treatment facilities 516 may also include processing unit 1786.Processing unit 1786 may separate stream 1782 into a number of streams.Each of the streams may be rich in a predetermined component or apredetermined number of compounds. For example, processing unit 1786 mayseparate stream 1782 into first portion 1788 of stream 1782, secondportion 1790 of stream 1782, third portion 1792 of stream 1782, andfourth portion 1794 of stream 1782. First portion 1788 of stream 1782may include lighter hydrocarbon components such as methane and ethane.First portion 1788 of stream 1782 may flow from gas treatment unit 1796to power generation unit 1798.

[1858] Power generation unit 1798 may extract useable energy from thefirst portion of stream 1782. For example, stream 1782 may be producedunder pressure. Power generation unit 1798 may include a turbine thatgenerates electricity from the first portion of stream 1782. The powergeneration unit may also include, for example, a molten carbonate fuelcell, a solid oxide fuel cell, or other type of fuel cell. The extracteduseable energy may be provided to user 1800. User 1800 may include, forexample, treatment facilities 516, a heat source disposed within aformation, and/or a consumer of useable energy.

[1859] Second portion 1790 of stream 1782 may also include lighthydrocarbon components. For example, second portion 1790 of stream 1782may include, but is not limited to, methane and ethane. Second portion1790 of stream 1782 may be provided to natural gas pipeline 1801.Alternatively, second portion 1790 of stream 1782 may be provided to alocal market. The local market may be a consumer market or a commercialmarket. Second portion 1790 of stream 1782 may be used as an end productor an intermediate product depending on, for example, a composition ofthe light hydrocarbon components.

[1860] Third portion 1792 of stream 1782 may include liquefied petroleumgas (“LPG”). Major constituents of LPG may include hydrocarbonscontaining three or four carbon atoms such as propane and butane. Butanemay include n-butane or isobutane. LPG may also include relatively smallconcentrations of other hydrocarbons, such as ethene, propene, butene,and pentene. Some LPG may also include additional components. LPG may bea gas at atmospheric pressure and normal ambient temperatures. LPG maybe liquefied, however, when moderate pressure is applied or when thetemperature is sufficiently reduced. When such moderate pressure isreleased, LPG gas may have about 250 times a volume of LPG liquid.Therefore, large amounts of energy may be stored and transportedcompactly as LPG.

[1861] Third portion 1792 of stream 1782 may be provided to local market1802. The local market may include a consumer market or a commercialmarket. Third portion 1792 of stream 1782 may be used as an end productor an intermediate product. LPG may be used in applications, such asfood processing, aerosol propellants, and automotive fuel. LPG may beprovided for standard heating and cooking purposes as commercial propaneand/or commercial butane. Propane may be more versatile for general usethan butane because propane has a lower boiling point than butane.

[1862] Fourth portion 1794 of stream 1782 may flow from the gastreatment unit to hydrogen manufacturing unit 1804. Hydrogen-rich stream1806 is shown exiting hydrogen manufacturing unit 1804. Examples ofhydrogen manufacturing unit 1804 may include a steam reformer and acatalytic flameless distributed combustor with a hydrogen separationmembrane.

[1863]FIG. 185 illustrates an embodiment of a catalytic flamelessdistributed combustor that may be hydrogen manufacturing unit 1804.Examples of catalytic flameless distributed combustors with hydrogenseparation membranes are illustrated in U.S. Provisional Application No.60/273,354 filed on Mar. 5, 2001; U.S. patent application Ser. No.10/091,108 filed on Mar. 5, 2002; U.S. Provisional Application No.60/273,353 filed on Mar. 5, 2001; and U.S. patent application Ser. No.10/091,104 filed on Mar. 5, 2002, each of which is incorporated byreference as if fully set forth herein. A catalytic flamelessdistributed combustor may include fuel line 1808, oxidant line 1810,catalyst 1812, and membrane 1814. Fourth portion 1794 of stream 1782(shown in FIG. 184) may be provided to hydrogen manufacturing unit 1804as fuel 1816. Fuel 1816 within fuel line 1808 may mix within reactionvolume in annular space 1818 between the fuel line and the oxidant line.Reaction of the fuel with the oxidant in the presence of catalyst 1812may produce reaction products that include H₂. Membrane 1814 may allow aportion of the generated H₂ to pass into annular space 1820 betweenouter wall 1822 of oxidant line 1810 and membrane 1814. Excess fuelpassing out of fuel line 1808 may be circulated back to an entrance ofhydrogen manufacturing unit 1804. Combustion products leaving oxidantline 1810 may include carbon dioxide and other reactions product as wellas some fuel and oxidant. The fuel and oxidant may be separated andrecirculated back to hydrogen manufacturing unit 1804. Carbon dioxidemay be separated from the exit stream. The carbon dioxide may besequestered within a portion of a formation or used for an alternatepurpose.

[1864] Fuel line 1808 may be concentrically positioned within oxidantline 1810. Critical flow orifices 1824 within fuel line 1808 may allowfuel to enter into a reaction volume in annular space 1818 between thefuel line and oxidant line 1810. The fuel line may carry a mixture ofwater and vaporized hydrocarbons such as, but not limited to, methane,ethane, propane, butane, methanol, ethanol, or combinations thereof. Theoxidant line may carry an oxidant such as, but not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, or combinations thereof.

[1865] Catalyst 1812 may be located in the reaction volume to allowreactions that produce H₂ to proceed at relatively low temperatures.Without a catalyst and without membrane separation of H₂, a steamreformation reaction may need to be conducted in a series of reactorswith temperatures for a shift reaction occurring in excess of 980° C.With a catalyst and with separation of H₂ from the reaction stream, thereaction may occur at temperatures within a range from about 300° C. toabout 600° C., or within a range from about 400° C. to about 500° C.Catalyst 1812 may be any steam reforming catalyst. In selectedembodiments, catalyst 1812 is a group VIII transition metal, such asnickel. The catalyst may be supported on porous substrate 1826. Thesubstrate may include group III or group IV elements, such as, but notlimited to, aluminum, silicon, titanium, or zirconium. In an embodiment,the substrate is alumina (Al₂O₃).

[1866] Membrane 1814 may remove H₂ from a reaction stream within areaction volume of a hydrogen manufacturing unit 1804. When H₂ isremoved from the reaction stream, reactions within the reaction volumemay generate additional H₂. A vacuum may draw H₂ from an annular regionbetween membrane 1814 and outer wall 1822 of oxidant line 1810.Alternately, H₂ may be removed from the annular region in a carrier gas.Membrane 1814 may separate H₂ from other components within the reactionstream. The other components may include, but are not limited to,reaction products, fuel, water, and hydrogen sulfide. The membrane maybe a hydrogen-permeable and hydrogen selective material such as, but notlimited to, a ceramic, carbon, metal, or combination thereof. Themembrane may include, but is not limited to, metals of group VIII, V,III, or I such as palladium, platinum, nickel, silver, tantalum,vanadium, yttrium, and/or niobium. The membrane may be supported on aporous substrate such as alumina. The support may separate membrane 1814from catalyst 1812. The separation distance and insulation properties ofthe support may help to maintain the membrane within a desiredtemperature range.

[1867] Hydrogen manufacturing unit 1804 of the treatment facilitiesembodiment depicted in FIG. 184 may produce hydrogen-rich stream 1806from fourth portion 1794. Hydrogen-rich stream 1806 may flow intohydrogen stream 1780 to form stream 1828. Stream 1828 may include alarger volume of hydrogen than either hydrogen-rich stream 1806 orhydrogen stream 1780.

[1868] Hydrocarbon condensate stream 1772 may flow through a conduitfrom separator 1768 to hydrotreating unit 1830. Hydrotreating unit 1830may hydrogenate hydrocarbon condensate stream 1772 to form hydrogenatedhydrocarbon condensate stream 1832. The hydrotreater may upgrade andswell the hydrocarbon condensate. Treatment facilities 516 may providestream 1828 (which includes a relatively high concentration of hydrogen)to hydrotreating unit 1830. H₂ in stream 1828 may hydrogenate a doublebond of the hydrocarbon condensate, thereby reducing a potential forpolymerization of the hydrocarbon condensate. In addition, hydrogen mayalso neutralize radicals in the hydrocarbon condensate. The hydrogenatedhydrocarbon condensate may include relatively short chain hydrocarbonfluids. Furthermore, hydrotreating unit 1830 may reduce sulfur,nitrogen, and aromatic hydrocarbons in hydrocarbon condensate stream1772. Hydrotreating unit 1830 may be a deep hydrotreating unit or a mildhydrotreating unit. An appropriate hydrotreating unit may vary dependingon, for example, a composition of stream 1828, a composition of thehydrocarbon condensate stream, and/or a selected composition of thehydrogenated hydrocarbon condensate stream.

[1869] Hydrogenated hydrocarbon condensate stream 1832 may flow fromhydrotreating unit 1830 to transportation unit 1834. Transportation unit1834 may collect a volume of the hydrogenated hydrocarbon condensateand/or to transport the hydrogenated hydrocarbon condensate to marketcenter 1836. Market center 1836 may include, but is not limited to, aconsumer marketplace or a commercial marketplace. A commercialmarketplace may include a refinery. The hydrogenated hydrocarboncondensate may be used as an end product or an intermediate product.

[1870] Alternatively, hydrogenated hydrocarbon condensate stream 1832may flow to a splitter or an ethene production unit. The splitter mayseparate the hydrogenated hydrocarbon condensate stream into ahydrocarbon stream including components having carbon numbers of 5 or 6,a naphtha stream, a kerosene stream, and/or a diesel stream. Selectedstreams exiting the splitter may be fed to the ethene production unit.In addition, the hydrocarbon condensate stream and the hydrogenatedhydrocarbon condensate stream may be fed to the ethene production unit.Ethene produced by the ethene production unit may be fed to apetrochemical complex to produce base and industrial chemicals andpolymers. Alternatively, the streams exiting the splitter may be fed toa hydrogen conversion unit. A recycle stream may flow from the hydrogenconversion unit to the splitter. The hydrocarbon stream exiting thesplitter and the naphtha stream may be fed to a mogas production unit.The kerosene stream and the diesel stream may be distributed as product.

[1871]FIG. 186 illustrates an embodiment of an additional processingunit that may be included in treatment facilities 516, such as thefacilities depicted in FIG. 184. Air 1620 may be fed to air separationunit 1838. Air separation unit 1838 may generate nitrogen stream 1840and oxygen stream 1842. In some embodiments, oxygen stream 1842 andsteam 1392 may be injected into formation 678 that has previouslyundergone a pyrolysis phase of an in situ conversion process to generatesynthesis gas 1502. In some embodiments, a portion or all of producedsynthesis gas 1502 may be provided to Shell Middle Distillates processunit 1844 that produces middle distillates 1846. In some embodiments, aportion or all of produced synthesis gas 1502 may be provided tocatalytic methanation process unit 1848 that produces natural gas 1850.A portion or all of produced synthesis gas 1502 may also be provided tomethanol production unit 1852 to produce methanol 1854. A portion or allof produced synthesis gas 1502 may be provided to process unit 1856 forproduction of ammonia and/or urea 1858. Synthesis gas may be used as afuel for fuel cell 1536 that produces electricity 1518A. A portion orall of produced synthesis gas 1502 may be routed to power generationunit 1798, such as a turbine or combustor, to produce electricity 1518B.

[1872] Comparisons of patterns of heat sources were evaluated forpatterns having substantially the same heater well density and the sameheating input regime. For example, a number of heat sources per unitarea in a triangular pattern is the same as the number of heat sourcesper unit area in the 10 m hexagonal pattern if the space between heatsources is increased to about 12.2 m in the triangular pattern. Theequivalent spacing for a square pattern would be 11.3 m, while theequivalent spacing for a 12:1 pattern would be 15.7 m.

[1873]FIG. 187 illustrates temperature profile 1860 after three years ofheating for a triangular pattern with a 12.2 m spacing in a typicalGreen River oil shale. FIG. 180 depicts an embodiment of a triangularpattern. Temperature profile 1860 is a three-dimensional plot oftemperature versus a location within a triangular pattern. FIG. 188illustrates temperature profile 1862 after three years of heating for asquare pattern with 11.3 m spacing in a typical Green River oil shale.Temperature profile 1862 is a three-dimensional plot of temperatureversus a location within a square pattern. FIG. 181 depicts anembodiment of a square pattern. FIG. 189 illustrates temperature profile1864 after three years of heating for a hexagonal pattern with 10.0 mspacing in a typical Green River oil shale. Temperature profile 1864 isa three-dimensional plot of temperature versus a location within ahexagonal pattern. FIG. 182 depicts an embodiment of a hexagonalpattern.

[1874] As shown in a comparison of FIGS. 187, 188, and 189, atemperature profile of the triangular pattern is more uniform than atemperature profile of the square or hexagonal pattern. For example, aminimum temperature of the square pattern is approximately 280° C., anda minimum temperature of the hexagonal pattern is approximately 250° C.In contrast, a minimum temperature of the triangular pattern isapproximately 300° C. Therefore, a temperature variation within thetriangular pattern after 3 years of heating is 20° C. less than atemperature variation within the square pattern and 50° C. less than atemperature variation within the hexagonal pattern. For a chemicalprocess, where reaction rate is proportional to an exponent oftemperature, a 20° C. difference may have a substantial effect onproducts being produced in a pyrolysis zone.

[1875]FIG. 190 illustrates a comparison plot of simulation resultsshowing the average pattern temperature (in degrees Celsius) andtemperatures at the coldest spots for each pattern as a function of time(in years). The coldest spot for each pattern is located at a patterncenter (centroid). As shown in FIG. 180, the coldest spot of atriangular pattern is point 1866. Curve 1874 of FIG. 190 depictstemperature as a function of time at point 1866. As shown in FIG. 181,the coldest spot of a square pattern is point 1868. Curve 1876 of FIG.190 depicts temperature as a function of time at point 1868. As shown inFIG. 182, the coldest spot of a hexagonal pattern is point 1870. Curve1878 of FIG. 190 depicts temperature as a function of time at point1870. As shown in FIG. 183, the coldest spot of a 12:1 pattern is point1872. Curve 1880 of FIG. 190 depicts temperature as a function of timeat point 1872. The difference between an average pattern temperature andtemperature of the coldest spot represents how uniform the temperaturedistribution for a given pattern is. The more uniform the heating, thebetter the product quality that may be made in the formation. The largerthe volume fraction of resource that is overheated, the greater theamount of undesirable product tends to be made.

[1876] In simulations, heat input into each of the various patterns wasa constant. The constant heat input into the formation results inaverage temperature curve 1882 for each pattern. As shown in FIG. 190,the difference between average temperature curve 1882 and curve 1874 fortemperature of the coldest spot is less for triangular pattern than forcurve 1876 for square pattern, curve 1878 for hexagonal pattern, orcurve 1880 for 12:1 pattern. There appears to be a substantialdifference between triangular and hexagonal patterns.

[1877] Another way to assess the uniformity of temperature distributionis to compare temperatures of the coldest spot of a pattern with a pointlocated at the center of a side of a pattern midway between heaters. Asshown in FIG. 180, point 1884 is located at the center of a side of atriangular pattern midway between heaters. Point 1886 is located at thecenter of a side of the square pattern midway between heaters, as shownin FIG. 181. As shown in FIG. 182, point 1888 is located at the centerof a side of the hexagonal pattern midway between heaters.

[1878]FIG. 191 illustrates a comparison plot between average patterntemperature curve 1882 (in degrees Celsius), temperature at coldest spotcurve 1890 (corresponding to point 1866 in FIG. 180) for triangularpatterns, temperature at coldest spot curve 1892 (corresponding to point1870 in FIG. 182) for hexagonal patterns, temperature at mid-point curve1894 (corresponding to point 1884 in FIG. 180), and temperature atmid-point curve 1896 (corresponding to point 1888 in FIG. 182) as afunction of time (in years). FIG. 192 illustrates a comparison plotbetween average pattern temperature 1882 (in degrees Celsius),temperatures at coldest spot curve 1898 (corresponding to point 1868 inFIG. 181) and temperature at a mid-point curve 1900 (corresponding topoint 1886 in FIG. 181) as a function of time (in years), for a squarepattern.

[1879] As shown in a comparison of FIGS. 191 and 192, for each pattern,a temperature at a center of a side midway between heaters is higherthan a temperature at a center of the pattern. A difference between atemperature at a center of a side midway between heaters and a center ofthe hexagonal pattern increases substantially during the first year ofheating, and stays relatively constant afterward. A difference between atemperature at an outer lateral boundary and a center of the triangularpattern, however, is negligible. Therefore, a temperature distributionin a triangular pattern is more uniform than a temperature distributionin a hexagonal pattern. A square pattern also provides more uniformtemperature distribution than a hexagonal pattern, however, it is stillless uniform than a temperature distribution in a triangular pattern.

[1880] A triangular pattern of heat sources may have, for example, ashorter total process time than a square, hexagonal, or 12:1 pattern ofheat sources for the same heater well density. A total process time mayinclude a time required for an average temperature of a heated portionof a formation to reach a target temperature and a time required for atemperature at a coldest spot within the heated portion to reach thetarget temperature. For example, heat may be provided to the portion ofthe formation until an average temperature of the heated portion reachesthe target temperature. After the average temperature of the heatedportion reaches the target temperature, an energy supply to the heatsources may be reduced such that less or minimal heat may be provided tothe heated portion. An example of a target temperature may beapproximately 340° C. The target temperature, however, may varydepending on, for example, formation composition and/or formationconditions such as pressure.

[1881]FIG. 193 illustrates a comparison plot between the average patterntemperature curve and temperatures at the coldest spots for eachpattern, as a function of time when heaters are turned off after theaverage temperature reaches a target value. As shown in FIG. 193,average temperature curve 1882 of the formation reaches a targettemperature (about 340° C.) in approximately 3 years. As shown in FIG.193, temperature at the coldest point curve 1902 (corresponding to point1866) reaches the target temperature (about 340° C.) about 0.8 yearslater. A total process time for such a triangular pattern is about 3.8years when the heat input is discontinued when the target averagetemperature is reached. As shown in FIG. 193, a temperature at thecoldest point within the triangular pattern reaches the targettemperature (about 340° C.) before temperature at coldest point curve1904 (corresponding to point 1868) or temperature at the coldest pointcurve 1906 (corresponding to point 1870) reaches the target temperature.A temperature at the coldest point within the hexagonal pattern,however, reaches the target temperature after an additional time ofabout 2 years when the heaters are turned off upon reaching the targetaverage temperature. Therefore, a total process time for a hexagonalpattern is about 5.0 years. A total process time for heating a portionof a formation with a triangular pattern is 1.2 years less(approximately 25% less) than a total process time for heating a portionof a formation with a hexagonal pattern. In an embodiment, the power tothe heaters may be reduced or turned off when the average temperature ofthe pattern reaches a target level. This prevents overheating theresource, which wastes energy and produces lower product quality. Thetriangular pattern has the most uniform temperatures and the leastoverheating. Although a capital cost of such a triangular pattern may beapproximately the same as a capital cost of the hexagonal pattern, thetriangular pattern may accelerate oil production and require. a shortertotal process time.

[1882] A triangular pattern may be more economical than a hexagonalpattern. A spacing of heat sources in a triangular pattern that willhave about the same process time as a hexagonal pattern having about a10.0 m space between heat sources may be equal to approximately 14.3 m.The triangular pattern may include about 26% less heat sources than theequivalent hexagonal pattern. Using the triangular pattern may allow forlower capital cost (i.e., there are fewer heat sources and productionwells) and lower operating costs (i.e., there are fewer heat sources andproduction wells to power and operate).

[1883]FIG. 57 depicts an embodiment of a natural distributed combustor.In one experiment, the embodiment schematically shown in FIG. 57 wasused to heat high volatile bituminous C coal in situ. A portion of aformation was heated with electrical resistance heaters and/or a naturaldistributed combustor. Thermocouples were located every 2 feet along thelength of the natural distributed combustor (along conduit 1092schematically shown in FIG. 57). The coal was first heated withelectrical resistance heaters until pyrolysis was complete near thewell. FIG. 194 depicts square data points measured during electricalresistance heating at various depths in the coal after the temperatureprofile had stabilized (the coal seam was about 16 feet thick startingat about 28 feet of depth). At this point heat energy was being suppliedat about 300 watts per foot. Air was subsequently injected via conduit1092 at gradually increasing rates, and electric power supplied to theelectrical resistance heaters was decreased. Combustion products wereremoved from the reaction volume through an annular space betweenconduit 1092 and a well casing. The power supplied to the electricalresistance heaters was decreased at a rate that would approximatelyoffset heating provided by the combustion of the coal adjacent toconduit 1092. Air input was increased and power input was decreased overa period of about 2 hours until no electric power was being supplied.

[1884] Diamond data points of FIG. 194 depict temperature as a functionof depth for natural distributed combustion heating (without anyelectrical resistance heating) in the coal after the temperature profilehad substantially stabilized. As can be seen in FIG. 194, the naturaldistributed combustion heating provided a temperature profile that iscomparable to the electrical resistance temperature profile (representedby square data points). This experiment demonstrated that naturaldistributed combustors may provide formation heating that is comparableto the formation heating provided by electrical resistance heaters. Thisexperiment was repeated at different temperatures and in two otherwells, all with similar results.

[1885] Numerical calculations have been made for a natural distributedcombustor system that heats a hydrocarbon containing formation. Acommercially available program called PRO-II (Simulation Sciences Inc.,Brea, Calif.) was used to make example calculations based on a conduitof diameter 6.03 cm with a wall thickness of 0.39 cm. The conduit wasdisposed in an opening in the formation with a diameter of 14.4 cm. Theconduit had critical flow orifices of 1.27 mm diameter spaced 183 cmapart. The conduit heated a formation of 91.4 m thickness. A flow rateof air was 1.70 standard cubic meters per minute through the criticalflow orifices. Pressure of air at the inlet of the conduit was 7 barsabsolute. Exhaust gases had a pressure of 3.3 bars absolute. A heatingoutput of 1066 watts per meter was used. A temperature in the openingwas set at 760° C. The calculations determined a minimal pressure dropwithin the conduit of about 0.023 bars. The pressure drop within theopening was less than 0.0013 bars.

[1886]FIG. 195 illustrates extension (in meters) of a reaction zonewithin a coal formation over time (in years) according to the parametersset in the calculations. The width of the reaction zone increases withtime due to oxidation of carbon adjacent to the conduit.

[1887] Numerical calculations have been made for heat transfer using aconductor-in-conduit heater. Calculations were made for a conductorhaving a diameter of about 1 inch (2.54 cm) disposed in a conduit havinga diameter of about 3 inches (7.62 cm). The conductor-in-conduit heaterwas disposed in an opening of a carbon containing formation having adiameter of about 6 inches (15.24 cm). An emissivity of the carboncontaining formation was maintained at a value of 0.9, which is expectedfor geological materials. The conductor and the conduit were givenalternate emissivity values of high emissivity (0.86), which is commonfor oxidized metal surfaces, and low emissivity (0.1), which is forpolished and/or un-oxidized metal surfaces. The conduit was filled witheither air or helium. Helium is known to be a more thermally conductivegas than air. The space between the conduit and the opening was filledwith a gas mixture of methane, carbon dioxide, and hydrogen gases. Twodifferent gas mixtures were used. The first gas mixture had molefractions of 0.5 for methane, 0.3 for carbon dioxide, and 0.2 forhydrogen. The second gas mixture had mole fractions of 0.2 for methane,0.2 for carbon dioxide, and 0.6 for hydrogen.

[1888]FIG. 196 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature of a face ofthe hydrocarbon containing formation in the opening for an air filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values, thermal conductivities,dimensions of the conductor, conduit, and opening, and the temperatureof the conduit. Line 1908 is calculated for the low emissivity value(0.1). Line 1910 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit provides for a higherratio of conductive to radiative heat transfer to the formation. Thedecrease in the ratio with an increase in temperature may be due to areduction of conductive heat transfer with increasing temperature. Asthe temperature on the face of the formation increases, a temperaturedifference between the face and the heater is reduced, thus reducing atemperature gradient that drives conductive heat transfer.

[1889]FIG. 197 illustrates a calculated ratio of conductive heattransfer to radiative heat transfer versus a temperature at a face ofthe carbon containing formation in the opening for a helium filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values; thermal conductivities;dimensions of the conductor, conduit, and opening; and the temperatureof the conduit. Line 1912 is calculated for the low emissivity value(0.1). Line 1914 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit again provides for ahigher ratio of conductive to radiative heat transfer to the formation.The use of helium instead of air in the conduit significantly increasesthe ratio of conductive heat transfer to radiative heat transfer. Thismay be due to a thermal conductivity of helium being about 5.2 to about5.3 times greater than a thermal conductivity of air.

[1890]FIG. 198 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 1916was linearly increased from 93° C. to 871° C. Opening temperature 1916was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 1918 and conduit temperature1920 were calculated from opening temperature 1916 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening begin toequilibrate.

[1891]FIG. 199 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 1916was linearly increased from 93° C. to 871° C. Opening temperature 1916was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 1918 and conduit temperature1920 were calculated from opening temperature 1916 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with air, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening begin toequilibrate, as seen for the helium filled conduit with high emissivity.

[1892]FIG. 200 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for a helium filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 1916was linearly increased from 93° C. to 871° C. Opening temperature 1916was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 1918 and conduit temperature1920 were calculated from opening temperature 1916 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases(helium, methane, carbon dioxide, and hydrogen). It may be seen from theplots of temperatures of the conductor, conduit, and opening for theconduit filled with helium, that at higher temperatures approaching 871°C., the temperatures of the conductor, conduit, and opening do not beginto equilibrate as seen for the high emissivity example shown in FIG.198. In addition, higher temperatures in the conductor and the conduitare needed to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in a carbon containing formation. Such reducedoperating temperatures may allow for the use of less expensive alloysfor metallic conduits.

[1893]FIG. 201 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the carbon containingformation for an air filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 1916was linearly increased from 93° C. to 871° C. Opening temperature 1916was assumed to be the same as the temperature at the face of the carboncontaining formation. Conductor temperature 1918 and conduit temperature1920 were calculated from opening temperature 1916 using the dimensionsof the conductor, conduit, and opening, values of emissivities for theconductor, conduit, and face, and thermal conductivities for gases (air,methane, carbon dioxide, and hydrogen). It may be seen from the plots oftemperatures of the conductor, conduit, and opening for the conduitfilled with helium, that at higher temperatures approaching 871° C., thetemperatures of the conductor, conduit, and opening do not begin toequilibrate as seen for the high emissivity example shown in FIG. 199.In addition, higher temperatures in the conductor and the conduit areneeded to achieve an opening and face temperature of 871° C. Thus,increasing an emissivity of the conductor and the conduit may beadvantageous in reducing operating temperatures needed to produce adesired temperature in a carbon containing formation. Such reducedoperating temperatures may provide for a lesser metallurgical costassociated with materials that require less substantial temperatureresistance (e.g., a lower melting point).

[1894] Calculations were also made using the first mixture of gas havinga hydrogen mole fraction of 0.2. The calculations resulted insubstantially similar results to those for a hydrogen mole fraction of0.6.

[1895]FIG. 202 depicts a retort and collection system used to conductcertain experiments. Retort vessel 1922 was a pressure vessel of 316stainless steel for holding a material to be tested. The vessel andappropriate flow lines were wrapped with a 0.0254 m by 1.83 m electricheating tape. The wrapping provided substantially uniform heatingthroughout the retort system. The temperature was controlled bymeasuring a temperature of the retort vessel with a thermocouple andaltering the electrical input to the heating tape with a proportionalcontroller to approach a desired set point. Insulation surrounded theheating tape. The vessel sat on a 0.0508 m thick insulating block. Theheating tape extended past the bottom of the stainless steel vessel tocounteract heat loss from the bottom of the vessel.

[1896] A 0.00318 m stainless steel dip tube 1924 was inserted throughmesh screen 1926 and into the small dimple on the bottom of vessel 1922.Dip tube 1924 was slotted near an end to inhibit plugging of the diptube. Mesh screen 1926 was supported along the cylindrical wall of thevessel by a small ring having a thickness of about 0.00159 m. The smallring provides a space between an end of dip tube 1924 and a bottom ofretort vessel 1922 to inhibit solids from plugging the dip tube. Athermocouple was attached to the outside of the vessel to measure atemperature of the steel cylinder. The thermocouple was protected fromdirect heat of the heater by a layer of insulation. Air-operateddiaphragm type backpressure valve 1928 was provided for tests atelevated pressures. The products at atmospheric pressure passed intoconventional glass laboratory condenser 1930. Coolant disposed in thecondenser 1930 was chilled water having a temperature of about 1.7° C.The oil vapor and steam products condensed in the flow lines of thecondenser flowed into the graduated glass collection tube. A volume ofproduced oil and water was measured visually. Non-condensable gas flowedfrom condenser 1930 through gas bulb 1932. Gas bulb 1932 has a capacityof 500 cm³. In addition, gas bulb 1932 was originally filled withhelium. The valves on the bulb were two-way valves 1934 to provide easypurging of bulb 1932 and removal of non-condensable gases for analysis.Considering a sweep efficiency of the bulb, the bulb would be expectedto contain a composite sample of the previously produced 1 to 2 litersof gas. Standard gas analysis methods were used to determine the gascomposition. The gas exiting the bulb passed into collection vessel 1936that is in water 1524 in water bath 1938. Water bath 1938 was graduatedto provide an estimate of the volume of the produced gas over a time ofthe procedure (the water level changed, thereby indicating the amount ofgas produced). Collection vessel 1936 also included an inlet valve at abottom of the collection system under water and a septum at a top of thecollection system for transfer of gas samples to an analyzer.

[1897] At location 1940 one or more gases may be injected into thesystem shown in FIG. 202 to pressurize, maintain pressure, or sweepfluids in the system. Pressure gauge 1942 may be used to monitorpressure in the system. Heating/insulating material 1944 (e.g.,insulation or a temperature control bath) may be used to regulate and/ormaintain temperatures. Controller 1946 may be used to control heating ofvessel 1922.

[1898] A final volume of gas produced is not the volume of gas collectedover water because carbon dioxide and hydrogen sulfide are soluble inwater. Analysis of the water has shown that the gas collection systemover water removes about a half of the carbon dioxide produced in atypical experiment. The concentration of carbon dioxide in water affectsa concentration of the non-soluble gases collected over water. Inaddition, the volume of gas collected over water was found to vary fromabout one-half to two-thirds of the volume of gas produced.

[1899] The system was purged with about 5 to 10 pore volumes of heliumto remove all air and pressurized to about 20 bars absolute for 24 hoursto check for pressure leaks. Heating was then started slowly, takingabout 4 days to reach 260° C. After about 8 to 12 hours at 260° C., thetemperature was raised as specified by the schedule desired for theparticular test. Readings of temperature on the inside and outside ofthe vessel were recorded frequently to assure that the controller wasworking correctly.

[1900] In one experiment, oil shale was tested in the system shown inFIG. 202. In this experiment, 270° C. was about the lowest temperatureat which oil was generated at any appreciable rate. Water productionstarted at about 100° C. and was monitored at all times during the run.Various amounts of gas were generated during the course of production.Gas production was monitored throughout the run.

[1901] Oil and water production were collected in 4 or 5 fractionsthroughout the run. These fractions were composite samples over aparticular time interval involved. The cumulative volume of oil andwater in each fraction was measured as it accrued. After each fractionwas collected, the oil was analyzed as desired. The density of the oilwas measured.

[1902] After the test, the retort was cooled, opened, and inspected forevidence of any liquid residue. A representative sample of the crushedshale loaded into the retort was taken and analyzed for oil generatingpotential by the Fischer Assay method. After the test, three samples ofspent shale in the retort were taken: one near the top, one at themiddle, and one near the bottom. These samples were tested for remainingorganic matter and elemental analysis.

[1903] Experimental data from the experiment described above was used todetermine a pressure-temperature relationship relating to the quality ofthe produced fluids. Varying the operating conditions included alteringtemperatures and pressures. Various samples of oil shale were pyrolyzedat various operating conditions. The quality of the produced fluids wasdescribed by a number of desired properties. Desired properties includedAPI gravity, an ethene to ethane ratio, an atomic carbon to atomichydrogen ratio, equivalent liquids produced (gas and liquid), liquidsproduced, percent of Fischer Assay, and percent of fluids with carbonnumbers greater than about 25. Based on data collected in theseequilibrium experiments, families of curves for several values of eachof the properties were constructed as shown in FIGS. 203-209. EQNS. 64,65, and 66 were used to describe the functional relationship of a givenvalue of a property:

P=exp[(A/T)+B],  (64)

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (65)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄.  (66)

[1904] The generated curves may be used to determine a selectedtemperature and a selected pressure for producing fluids with desiredproperties.

[1905] In FIG. 203, a plot of gauge pressure versus temperature isdepicted (in FIGS. 203-209 the pressure is indicated in bars). Linesrepresenting the fraction of products with carbon numbers greater thanabout 25 were plotted. For example, when operating at a temperature of375° C. and a pressure of 4.5 bars absolute, 15% of the produced fluidhydrocarbons had a carbon number equal to or greater than 25. At lowpyrolysis temperatures and high pressures, the fraction of producedfluids with carbon numbers greater than about 25 decreases. Therefore,operating at a high pressure and a pyrolysis temperature at the lowerend of the pyrolysis temperature zone may decrease the fraction offluids with carbon numbers greater than 25 produced from oil shale.

[1906]FIG. 204 illustrates oil quality produced from an oil shaleformation as a function of pressure and temperature. Lines indicatingdifferent oil qualities, as defined by API gravity, are plotted. Forexample, the quality of the produced oil was 40° API when pressure wasmaintained at about 11.1 bars absolute and a temperature was about 375°C. Low pyrolysis temperatures and relatively high pressures may producea high API gravity oil.

[1907]FIG. 205 illustrates an ethene to ethane ratio produced from anoil shale formation as a function of pressure and temperature. Forexample, at a pressure of 21.7 bars absolute and a temperature of 375°C., the ratio of ethene to ethane is approximately 0.01. The volumeratio of ethene to ethane may predict an olefin to alkane ratio ofhydrocarbons produced during pyrolysis. Olefin content may be reduced byoperating at temperatures at a lower end of a pyrolysis temperaturerange and at a high pressure.

[1908]FIG. 206 depicts the dependence of yield of equivalent liquidsproduced from an oil shale formation as a function of temperature andpressure. Line 1948 represents the pressure-temperature combination atwhich 8.38×10⁻⁵ m³ of fluid per kilogram of oil shale (20 gallons/ton)was produced. The pressure/temperature plot results in line 1950 for theproduction of total fluids per ton of oil shale equal to 1.05×10⁻⁴ m³/kg(25 gallons/ton). Line 1952 illustrates that 1.21×10⁻⁴ m³ of fluid wasproduced from 1 kilogram of oil shale (30 gallons/ton). At a temperatureof about 325° C. and a pressure of about 14.8 bars absolute, theresulting equivalent liquids produced was 8.38×10⁻⁵ m³/kg. Astemperature of the retort increased and the pressure decreased, theyield of the equivalent liquids produced increased. Equivalent liquidsproduced is defined as the amount of liquids equivalent to the energyvalue of the produced gas and liquids.

[1909]FIG. 207 illustrates a plot of oil yield produced from treating anoil shale formation, measured as volume of liquids per ton of theformation, as a function of temperature and pressure of the retort.Temperature is illustrated in units of Celsius on the x-axis, andpressure is illustrated in units of bars absolute on the y-axis. Asshown in FIG. 207, the yield of liquid/condensable products increases astemperature of the retort increases and pressure of the retortdecreases. The lines on FIG. 207 correspond to different liquidproduction rates measured as the volume of liquids produced per weightof oil shale. The data is tabulated in TABLE 20. TABLE 20 LINE VOLUMEPRODUCED/MASS OF OIL SHALE (m³/kg) 1954 5.84 × 10⁻⁵ 1956 6.68 × 10⁻⁵1958 7.51 × 10⁻⁵ 1960 8.35 × 10⁻⁵

[1910]FIG. 208 illustrates yield of oil produced from treating an oilshale formation expressed as a percent of Fischer Assay as a function oftemperature and pressure. Temperature is illustrated in units of degreesCelsius on the x-axis, and gauge pressure is illustrated in units ofbars on the y-axis. Fischer Assay was used as a method for assessing arecovery of hydrocarbon condensate from the oil shale. In this case, amaximum recovery would be 100% of the Fischer Assay. As the temperaturedecreased and the pressure increased, the percent of Fischer Assay yielddecreased.

[1911]FIG. 209 illustrates hydrogen to carbon ratio of hydrocarboncondensate produced from an oil shale formation as a function of atemperature and pressure. Temperature is illustrated in units of degreesCelsius on the x-axis, and pressure is illustrated in units of bars onthe y-axis. As shown in FIG. 209, a hydrogen to carbon ratio ofhydrocarbon condensate produced from an oil shale formation decreases asa temperature increases and as a pressure decreases. Treating an oilshale formation at high temperatures may decrease a hydrogenconcentration of the produced hydrocarbon condensate.

[1912]FIG. 210 illustrates the effect of pressure and temperature withinan oil shale formation on a ratio of olefins to paraffins. Therelationship of the value of one of the properties (R) with temperaturehas the same functional form as the pressure-temperature relationshipspreviously discussed. In this case, the property (R) can be explicitlyexpressed as a function of pressure and temperature, as in EQNS. 67, 68,and 69.

R=exp[F(P)/T)+G(P)]  (67)

F(P)=f ₁*(P)³ +f ₂*(P)² +f ₃*(P)+f ₄  (68)

G(P)=g ₁*(P)³ +g ₂*(P)² +g ₃*(P)+g ₄  (69)

[1913] wherein R is a value of the property, T is the absolutetemperature (in Kelvin), and F(P) and G(P) are functions of pressurerepresenting the slope and intercept of a plot of R versus 1/T.

[1914] Data from experiments were compared to data from other sources.Isobars were plotted on a temperature versus olefin to paraffin ratiograph using data from a variety of sources. Data from the experimentsincluded isobars at 1 bar absolute 1962, 2.5 bars absolute 1964, 4.5bars absolute 1966, 7.9 bars absolute 1968, and 14.8 bars absolute 1970.Additional data plotted included data from a surface retort, data fromLjungstrom 1972, and data from ex situ oil shale studies conducted byLawrence Livermore Laboratories 1974. As illustrated in FIG. 210, theolefin to paraffin ratio appears to increase as the pyrolysistemperature increases. However, for a fixed temperature, the ratiodecreases rapidly with an increase in pressure. Higher pressures andlower temperatures appear to favor the lowest olefin to paraffin ratios.At a temperature of about 350° C. and a pressure of about 7.9 barsabsolute 1968, a ratio of olefins to paraffins was approximately 0.01.Pyrolyzing at reduced temperature and increased pressure may decrease anolefin to paraffin ratio. Pyrolyzing hydrocarbons for a longer period oftime, which may be accomplished by increasing pressure within thesystem, may result in a lower average molecular weight oil. In addition,production of gas may increase when pressure is increased. Anon-volatile coke may be formed in the formation.

[1915]FIG. 211 illustrates a relationship between an API gravity of ahydrocarbon condensate fluid, the partial pressure of molecular hydrogenwithin the fluid, and a temperature within an oil shale formation. Asillustrated in FIG. 211, as a partial pressure of hydrogen within thefluid increased, the API gravity generally increased. In addition, lowerpyrolysis temperatures appear to have increased the API gravity of theproduced fluids. Maintaining a partial pressure of molecular hydrogenwithin a heated portion of a hydrocarbon containing formation mayincrease the API gravity of the produced fluids.

[1916] In FIG. 212, a quantity of oil liquids produced in m³ of liquidsper kg of oil shale formation is plotted versus a partial pressure ofH₂. Also illustrated in FIG. 212 are various curves for pyrolysisoccurring at different temperatures. At higher pyrolysis temperatures,production of oil liquids was higher than at the lower pyrolysistemperatures. In addition, high pressures tended to decrease thequantity of oil liquids produced from an oil shale formation. Operatingan in situ conversion process at low pressures and high temperatures mayproduce a higher quantity of oil liquids than operating at lowtemperatures and high pressures.

[1917] As illustrated in FIG. 213, an ethene to ethane ratio in theproduced gas increased with increasing temperature. In addition,application of pressure decreased the ethene to ethane ratiosignificantly. As illustrated in FIG. 213, lower temperatures and higherpressures decreased the ethene to ethane ratio. The ethene to ethaneratio is indicative of the olefin to paraffin ratio in the condensedhydrocarbons.

[1918]FIG. 214 illustrates an atomic hydrogen to atomic carbon ratio inthe hydrocarbon liquids. In general, lower temperatures and higherpressures increased the atomic hydrogen to atomic carbon ratio of theproduced hydrocarbon liquids.

[1919] A small-scale field experiment of an in situ conversion processin oil shale was conducted. An objective of this test was tosubstantiate laboratory experiments that produced high quality crudeutilizing the in situ retort process.

[1920] As illustrated in FIG. 215, the field experiment consisted of asingle unconfined hexagonal seven spot pattern on eight foot spacing.Six heater wells 520, drilled to a depth of 40 m, contained 17 m longheating elements that injected thermal energy into the formation from 21m to 39 m. Production well 512 in the center of the pattern captured theliquids and vapors from the in situ retort. Three observation wells 1976inside the pattern and one outside the pattern recorded formationtemperatures and pressures. Six dewatering wells 1978 surrounded thepattern on 6 m spacing and were completed in an active aquifer below theheated interval (from 44 m to 61 m). FIG. 216 depicts a cross-sectionalrepresentation of the field experiment. Production well 512 includespump 538. Lower portion 1980 of production well 512 was packed withgravel. Upper portion 1982 of production well 512 was cemented. Heaterwells 520 were located a distance of approximately 2.4 m from productionwell 512. A heating element was located within the heater well and theheater well was cemented in place. Dewatering wells 1978 were locatedapproximately 4.0 m from heater wells 520. Coring well 1984 was locatedapproximately 0.5 m from heater wells 520.

[1921] Produced oil, gas, and water were sampled and analyzed throughoutthe life of the experiment. Surface and subsurface pressures andtemperatures and energy injection data were captured electronically andsaved for future evaluation. The composite oil produced from the testhad a 36° API gravity with a low olefin content of 1.1 weight % and aparaffin content of 66 weight %. The composite oil also included asulfur content of 0.4 weight %. This condensate-like crude confirmed thequality predicted from the laboratory experiments. The composition ofthe gas changed throughout the test. The gas was high in hydrogen(average approximately 25 mol %) and CO₂ (average approximately 15 mol%), as expected.

[1922] Evaluation of the post heat core indicates that the oil shalezone was thoroughly retorted except for the top and bottom 1 m to 1.2 m.Oil recovery efficiency was shown to be in the 75% to 80% range. Someretorting also occurred at least two feet outside of the pattern. Duringthe in situ conversion process experiment, the formation pressures weremonitored with pressure monitoring wells. The pressure increased to ahighest pressure at 9.4 bars absolute and then slowly declined. The highoil quality was produced at the highest pressure and temperatures below350° C. The pressure was allowed to decrease to atmospheric astemperatures increased above 370° C. As predicted, the oil compositionunder these conditions was shown to be of lower API gravity, highermolecular weight, greater carbon numbers in carbon number distribution,higher olefin content, and higher sulfur and nitrogen contents.

[1923]FIG. 217 illustrates a plot of the maximum temperatures withineach of three innermost observation wells 1976 (see FIG. 215) versustime. The temperature profiles were very similar for the threeobservation wells. Heat was provided to the oil shale formation for 216days. As illustrated in FIG. 217, the temperature at the observer wellsincreased steadily until the heat was turned off.

[1924]FIG. 218 illustrates a plot of hydrocarbon liquids production, inbarrels per day, for the same in situ experiment. In this figure, theline marked as “Separator Oil” indicates the hydrocarbon liquids thatwere produced after the produced fluids were cooled to ambientconditions and separated. In this figure the line marked as “Oil &C5+Gas Liquids” includes the hydrocarbon liquids produced after theproduced fluids were cooled to ambient conditions and separated and, inaddition, the assessed C₅ and heavier compounds that were flared. Thetotal liquid hydrocarbons produced to a stock tank during the experimentwas 194 barrels. The total equivalent liquid hydrocarbons produced(including the C₅ and heavier compounds) was 250 barrels. As indicatedin FIG. 218, the heat was turned off at day 216, however, somehydrocarbons continued to be produced thereafter.

[1925]FIG. 219 illustrates a plot of production of hydrocarbon liquids(in barrels per day), gas (in MCF per day), and water (in barrels perday), versus heat energy injected (in megawatt-hours), during the samein situ experiment. As shown in FIG. 219, the heat was turned off afterabout 440 megawatt-hours of energy had been injected.

[1926] As illustrated in FIG. 220, pressure within the oil shalematerial showed some variations initially at different depths, however,over time these variations equalized. FIG. 220 depicts the gauge fluidpressure in observation well 1976 versus time measured in days at aradial distance of 2.1 m from production well 512, shown in FIG. 215.The fluid pressures were monitored at depths of 24 m and 33 m. Thesedepths corresponded to a richness within the oil shale material of8.3×10⁻⁵ m³ of oil/kg of oil shale at 24 m and 1.7×10⁻⁴ m³ of oil/kg ofoil shale at 33 m. The higher pressures initially observed at 33 m maybe the result of a higher generation of fluids due to the richness ofthe oil shale material at that depth. In addition, at lower depths alithostatic pressure may be higher, causing the oil shale material at 33m to fracture at higher pressure than at 24 m. During the course of theexperiment, pressures within the oil shale formation equalized. Theequalization of the pressure may have resulted from fractures formingwithin the oil shale formation.

[1927]FIG. 221 is a plot of API gravity versus time measured in days. Asillustrated in FIG. 221, the API gravity was relatively high (i.e.,hovering around 40° until about 140 days). The API gravity, although itstill varied, decreased steadily thereafter. Prior to 110 days, thepressure measured at shallower depths was increasing, and after 110days, it began to decrease significantly. At about 140 days, thepressure at the deeper depths began to decrease. At about 140 days, thetemperature as measured at the observation wells increased above about370° C.

[1928] In FIG. 222 average carbon numbers of the produced fluid areplotted versus time measured in days. At approximately 140 days, theaverage carbon number of the produced fluids increased. Thisapproximately corresponded to the temperature rise and the drop inpressure illustrated in FIG. 217 and FIG. 220, respectively. Inaddition, as shown in FIG. 223, the density of the produced hydrocarbonliquids, in grams per cc, increased at approximately 140 days. Thequality of the produced hydrocarbon liquids, as demonstrated in FIG.221, FIG. 222, and FIG. 223, decreased as the temperature increased andthe pressure decreased.

[1929]FIG. 224 depicts a plot of the weight percent of specific carbonnumbers of hydrocarbons within the produced hydrocarbon liquids. Thevarious curves represent different times at which the liquids wereproduced. The carbon number distribution of the produced hydrocarbonliquids for the first 136 days exhibited a relatively narrow carbonnumber distribution, with a low weight percent of carbon numbers above16. The carbon number distribution of the produced hydrocarbon liquidsbecomes progressively broader as time progresses after 136 days (e.g.,from 199 days to 206 days to 231 days). As the temperature continued toincrease and the pressure had decreased towards one atmosphere absolute,the product quality steadily deteriorated.

[1930]FIG. 225 illustrates a plot of the weight percent of specificcarbon numbers of hydrocarbons within the produced hydrocarbon liquids.Curve 1986 represents the carbon distribution for the composite mixtureof hydrocarbon liquids over the entire in situ conversion process(“ICP”) field experiment. For comparison, a plot of the carbon numberdistribution for hydrocarbon liquids produced from a surface retort ofthe same Green River oil shale is also depicted as curve 1988. In thesurface retort, oil shale was mined, placed in a vessel, and rapidlyheated at atmospheric pressure to a high temperature in excess of 500°C. As illustrated in FIG. 225, a carbon number distribution of themajority of the hydrocarbon liquids produced from the ICP fieldexperiment was within a range of 8 to 15. The peak carbon number fromproduction of oil during the ICP field experiment was about 13. Incontrast, curve 1988 shows a relatively flat carbon number distributionwith a substantial amount of carbon numbers greater than 25. Inaddition, the acid number of oil produced from the ICP field experimentwas 0.14 mg/gram KOH.

[1931] During the ICP experiment, the formation pressures were monitoredwith pressure monitoring wells. The pressure increased to a highestpressure at 9.3 bars absolute and then slowly declined. The high oilquality was produced at the highest pressures and temperatures below350° C. The pressure was allowed to decrease to atmospheric astemperatures increased above 370° C. As predicted, the oil compositionunder these conditions was shown to be of lower API gravity, highermolecular weight, greater carbon numbers in the carbon numberdistribution, higher olefin content, and higher sulfur and nitrogencontents.

[1932] Experimental data from studies conducted by Lawrence LivermoreNational Laboratories (LLNL) was plotted along with laboratory data fromthe in situ conversion process (ICP) for an oil shale formation atatmospheric pressure in FIG. 226. The oil recovery as a percent ofFischer Assay was plotted against a log of the heating rate. Data fromLLNL 1990 included data derived from pyrolyzing powdered oil shale atatmospheric pressure and in a range from about 2 bars absolute to about2.5 bars absolute. As illustrated in FIG. 226, data from LLNL 1990 has alinear trend. Data from ICP 1992 demonstrates that oil recovery, asmeasured by Fischer Assay, was much higher for ICP than data from LLNL1990 would suggest. FIG. 226 shows that oil recovery from oil shale mayincrease along an S-curve, instead of linearly, as a function of heatingrate.

[1933] Results from the oil shale field experiment (e.g., measuredpressures, temperatures, produced fluid quantities and compositions,etc.) were input into a numerical simulation model to assess formationfluid transport mechanisms. FIG. 227 shows the results from the computersimulation. In FIG. 227, oil production 1994 in stock tank barrels/daywas plotted versus time. Area 1996 represents the liquid hydrocarbons inthe formation at reservoir conditions that were measured in the fieldexperiment. FIG. 227 indicates that more than 90% of the hydrocarbons inthe formation were vapors. Based on these results and the fact that thewells in the field test produced mostly vapors (until such vapors werecooled, at which point hydrocarbon liquids were produced), it isbelieved that hydrocarbons in the formation move through the formationprimarily as vapors when heated.

[1934] A series of experiments was conducted to determine the effects ofvarious properties of hydrocarbon containing formations on properties offluids produced from coal formations. The series of experiments includedorganic petrography, proximate/ultimate analyses, Rock-Eval pyrolysis,Leco Total Organic Carbon (“TOC”), Fischer Assay, and pyrolysis-gaschromatography. Such a combination of petrographic and chemicaltechniques may provide a quick and inexpensive method for determiningphysical and chemical properties of coal and for providing acomprehensive understanding of the effect of geochemical parameters onpotential oil and gas production from coal pyrolysis. The series ofexperiments were conducted on forty-five cubes of coal to determinesource rock properties of each coal and to assess potential oil and gasproduction from each coal.

[1935] Organic petrology is the study, mostly under the microscope, ofthe organic constituents of coal and other rocks. The ultimate analysisrefers to a series of defined methods that are used to determine thecarbon, hydrogen, sulfur, nitrogen, ash, oxygen, and the heating valueof a coal. Proximate analysis is the measurement of the moisture, ash,volatile matter, and fixed carbon content of a coal.

[1936] Rock-Eval pyrolysis is a petroleum exploration tool developed toassess the generative potential and thermal maturity of prospectivesource rocks. A ground sample may be pyrolyzed in a helium atmosphere.For example, the sample may be initially heated and held at atemperature of 300° C. for 5 minutes. The sample may be further heatedat a rate of 25° C./min to a final temperature of 600° C. The finaltemperature may be maintained for 1 minute. The products of pyrolysismay be oxidized in a separate chamber at 580° C. to determine the totalorganic carbon content. All components generated may be split into twostreams passing through a flame ionization detector, which measureshydrocarbons, and a thermal conductivity detector, which measures CO₂.

[1937] Leco Total Organic Carbon (“TOC”) involves combustion of coal.For example, a small sample (about 1 gram) is heated to 1500° C. in ahigh-frequency electrical field under an oxygen atmosphere. Conversionof carbon to carbon dioxide is measured volumetrically. Pyrolysis-gaschromatography may be used for quantitative and qualitative analysis ofpyrolysis gas.

[1938] Coal of different ranks and vitrinite reflectances were treatedin a laboratory to simulate an in situ conversion process. The differentcoal samples were heated at a rate of about 2° C./day and at a pressureof 1 bar or 4.4 bars absolute. FIG. 228 shows weight percents ofparaffins plotted against vitrinite reflectance. As shown in FIG. 228,weight percent of paraffins in the produced oil increases at vitrinitereflectances of the coal below about 0.9%. In addition, a weight percentof paraffins in the produced oil approaches a maximum at a vitrinitereflectance of about 0.9%. FIG. 229 depicts weight percentages ofcycloalkanes in the produced oil plotted versus vitrinite reflectance.As shown in FIG. 229, a weight percent of cycloalkanes in the oilproduced increased as vitrinite reflectance increased. Weightpercentages of a sum of paraffins and cycloalkanes is plotted versusvitrinite reflectance in FIG. 230. In some embodiments, an in situconversion process may be utilized to produce phenol. Phenol generationmay increase when a fluid pressure within the formation is maintained ata low pressure. Phenol weight percent in the produced oil is depicted inFIG. 231. A weight percent of phenol in the produced oil decreases asthe vitrinite reflectance increases. FIG. 232 illustrates a weightpercentage of aromatics in the hydrocarbon fluids plotted againstvitrinite reflectance. As shown in FIG. 232, a weight percent ofaromatics in the produced oil decreases below a vitrinite reflectance ofabout 0.9%. A weight percent of aromatics in the produced oil increasesabove a vitrinite reflectance of about 0.9%. FIG. 233 depicts a ratio ofparaffins to aromatics 1998 and a ratio of aliphatics to aromatics 2000plotted versus vitrinite reflectance. Both ratios increase to a maximumat a vitrinite reflectance between about 0.7% and about 0.9%. Above avitrinite reflectance of about 0.9%, both ratios decrease as vitrinitereflectance increases.

[1939]FIG. 234 depicts the condensable hydrocarbon compositions andcondensable hydrocarbon API gravities that were produced when variousranks of coal were treated as is described above for FIGS. 228-233. InFIG. 234, “SubC” means a rank of sub-bituminous C coal, “SubB” means arank of sub-bituminous B coal, “SubA” refers to a rank of sub-bituminousA coal, “HVC” refers to a rank of high volatile bituminous C coal,“HVB/A” refers to a rank of high volatile bituminous coal at the borderbetween B and A rank coal, “MV” refers to a rank medium volatilebituminous coal, and “Ro” refers to vitrinite reflectance. As can beseen in FIG. 234, certain ranks of coal will produce differentcompositions when treated by different methods. For instance, in manycircumstances it may be desirable to treat coal having a rank of HVB/Abecause such coal produces the highest API gravity, the highest weightpercent of paraffins, and the highest weight percent of the sum ofparaffins and cycloalkanes.

[1940] FIGS. 235-238 illustrate the yields of components in terms of m³of product per kg of hydrocarbon containing formation, when measured ona dry, ash free basis. As illustrated in FIG. 235 the yield of paraffinsincreased as the vitrinite reflectance of the coal increased. However,for coals with a vitrinite reflectance greater than about 0.7% to 0.8%,the yield of paraffins fell off dramatically. In addition, a yield ofcycloalkanes followed similar trends as the paraffins, increasing as thevitrinite reflectance of coal increased and decreasing for coals with avitrinite reflectance greater than about 0.7% or 0.8%, as illustrated inFIG. 236. FIG. 237 illustrates the increase of both paraffins andcycloalkanes as the vitrinite reflectance of coal increases to about0.7% or 0.8%. As illustrated in FIG. 238, the yield of phenols may berelatively low for coal material with a vitrinite reflectance of lessthan about 0.3% and greater than about 1.25%. Production of phenols maybe desired due to the value of phenol as a feedstock for chemicalsynthesis.

[1941] As demonstrated in FIG. 239, the API gravity appears to increasesignificantly when the vitrinite reflectance is greater than about 0.4%.FIG. 240 illustrates the relationship between coal rank, (i.e.,vitrinite reflectance), and a yield of condensable hydrocarbons (ingallons per ton on a dry ash free basis) from a coal formation. Theyield in this experiment appears to be in an optimal range when the coalhas a vitrinite reflectance greater than about 0.4% to less than about1.3%.

[1942]FIG. 241 illustrates a plot of CO₂ yield of coal having variousvitrinite reflectances. In FIGS. 241 and 242, CO₂ yield is expressed inweight percent on a dry ash free basis. As shown in FIG. 241, at leastsome CO₂ was produced from all of the coal samples. The CO₂ productionmay correspond to various oxygenated functional groups present in theinitial coal samples. A yield of CO₂ produced from low-rank coal sampleswas significantly higher than CO₂ production from high-rank coalsamples. Low-rank coals may include lignite and sub-bituminous browncoals. High-rank coals may include semi-anthracite and anthracite coal.FIG. 242 illustrates a plot of CO₂ yield from a portion of a coalformation versus the atomic O/C ratio within a portion of a coalformation. As O/C atomic ratio increases, a CO₂ yield increases.

[1943] A slow heating process may produce condensed hydrocarbon fluidshaving API gravities in a range of 22° to 50°, and average molecularweights of about 150 g/gmol to about 250 g/gmol. These properties may becompared to properties of condensed hydrocarbon fluids produced by exsitu retorting of coal as reported in Great Britain Published PatentApplication No. GB 2,068,014 A, which is incorporated by reference as iffully set forth herein. The ex situ process produced a lower qualityproduct than an in situ conversion process. For example, properties ofcondensed hydrocarbon fluids produced by an ex situ retort processinclude API gravities of 1.9° to 7.9° produced at temperatures of 521°C. and 427° C., respectively.

[1944] TABLE 21 shows a comparison of gas compositions, in percentvolume, obtained from in situ gasification of coal using air injectionto heat the coal, in situ gasification of coal using oxygen injection toheat the coal, and in situ gasification of coal in a reducing atmosphereby thermal pyrolysis heating as described in embodiments herein. TABLE21 Gasification Gasification Thermal Pyrolysis With Air With OxygenHeating H₂ 18.6% 35.5% 16.7% Methane 3.6% 6.9% 61.9% Nitrogen and Argon47.5% 0.0 0.0 Carbon Monoxide 16.5% 31.5% 0.9% Carbon Dioxide 13.1%25.0% 5.3% Ethane 0.6% 1.1% 15.2%

[1945] As shown in TABLE 21, gas produced according to an embodiment maybe treated and sold through existing natural gas systems. In contrast,gas produced by typical in situ gasification processes may not betreated and sold through existing natural gas systems. For example, aheating value of the gas produced by gasification with air was 6000kJ/m³, and a heating value of gas produced by gasification with oxygenwas 11,439 kJ/m³. In contrast, a heating value of the gas produced bythermal conductive heating was 39,159 kJ/m³.

[1946] Experiments were conducted to determine the difference betweentreating relatively large solid blocks of coal versus treatingrelatively small loosely packed particles of coal. As illustrated inFIG. 243, coal in cube 2002 was heated to pyrolyze the coal. Heat wasprovided to the coal from heat source 508A inserted into the center ofthe cube and also from heat sources 508B located on the sides of thecube. The cube was surrounded by insulation 2004. The temperature wasraised simultaneously using heat sources 508A, 508B at a rate of about2° C./day at atmospheric pressure. Measurements from temperature gauges2006 were used to determine an average temperature of cube 2002.Pressure in cube 2002 was monitored with pressure gauge 1942. The fluidsproduced from the cube of coal were collected and routed through conduit2008. Temperature of the product fluids was monitored with temperaturegauge 2006 on conduit 2008. A pressure of the product fluids wasmonitored with pressure gauge 1942 on conduit 2008. A hydrocarboncondensate was separated from a non-condensable fluid in separator 2010.Pressure in separator 2010 was monitored with pressure gauge 1942. Aportion of the non-condensable fluid was routed through conduit 2012 togas analyzers 2014 for characterization. Grab samples were taken fromgrab sample port 2016. Temperature of the non-condensable fluids wasmonitored with temperature gauge 2006 on conduit 2012. A pressure of thenon-condensable fluids was monitored with pressure gauge 1942 on conduit2012. The remaining gas was routed through flow meter 2018, carbon bed2020, and vented to the atmosphere. The produced hydrocarbon condensatewas collected and analyzed to determine the composition of thehydrocarbon condensate.

[1947]FIG. 244 illustrates an experimental drum apparatus. The drumapparatus was used to test coal. Electric heater 1132 and bead heater2022 were used to uniformly heat contents of drum 2024. Insulation 2004surrounds drum 2024. Contents of drum 2024 were heated at a rate ofabout 2° C./day at various pressures. Measurements from temperaturegauges 2006 were used to determine an average temperature in drum 2024.Pressure in the drum was monitored with pressure gauge 1942. Productfluids were removed from drum 2024 through conduit 2008. Temperature ofthe product fluids was monitored with temperature gauge 2006 on conduit2008. A pressure of the product fluids was monitored with pressure gauge1942 on conduit 2008. Product fluids were separated in separator 2010.Separator 2010 separated product fluids into condensable andnon-condensable products. Pressure in separator 2010 was monitored withpressure gauge 1942. Non-condensable product fluids were removed throughconduit 2012. A composition of a portion of non-condensable productfluids removed from separator 2010 was determined by gas analyzer 2014.A portion of condensable product fluids was removed from separator 2010.Compositions of the portion of condensable product fluids collected weredetermined by external analysis methods. Temperature of thenon-condensable fluids was monitored with temperature gauge 2006 onconduit 2012. A pressure of the non-condensable fluids was monitoredwith pressure gauge 1942 on conduit 2012. Flow of non-condensable fluidsfrom separator 2010 was determined by flow meter 2018. Fluids measuredin flow meter 2018 were collected and neutralized in carbon bed 2020.Gas samples were collected in gas container 2026.

[1948] A large block of high volatile bituminous B Fruitland coal wasseparated into two portions. One portion (about 550 kg) was ground intosmall pieces and tested in a coal drum. The coal was ground to anapproximate diameter of about 6.34×10⁻⁴ m. The results of such testingare depicted with the circles in FIGS. 245 and 246. One portion (a cubehaving sides measuring 0.3048 m) was tested in a coal cube experiment.The results of such testing are depicted with the squares in FIGS. 245and 246.

[1949]FIG. 245 is a plot of gas phase compositions from experiments on acoal cube and a coal drum for H₂ 2028, methane 2030, ethane 2032,propane 2034, n-butane 2036, and other hydrocarbons 2038 as a functionof temperature. As can be seen for FIG. 245, the non-condensable fluidsproduced from pyrolysis of the cube and the drum had similarconcentrations of the various hydrocarbons generated within the coal. InFIG. 245 these results were so similar that only one line was drawn forethane 2032, propane 2034, n-butane 2036, and other hydrocarbons 2038for both the cube and the drum results, and the two lines that weredrawn for H₂ (2028A and 2028B) and the two lines drawn for methane(2030A and 2030B) were in both instances very close to each other.Crushing the coal did not have an apparent effect on the pyrolysis ofthe coal. The peak in methane production 2030 occurred at about 450° C.At higher temperatures methane cracks to hydrogen, so the methaneconcentration decreases while hydrogen concentration increases.

[1950]FIG. 247 illustrates a plot of cumulative production of gas as afunction of temperature from heating coal in the cube and coal in thedrum. Line 2040 represents gas production from coal in the drum and line2042 represents gas production from coal in the cube. As demonstrated byFIG. 247, the production of gas in both experiments yielded similarresults, even though the particle sizes were dramatically differentbetween the two experiments.

[1951]FIG. 246 illustrates cumulative condensable hydrocarbons producedin the cube and drum experiments. Line 2044 represents cumulativecondensable hydrocarbons production from the cube experiment, and line2046 represents cumulative condensable hydrocarbons production from thedrum experiment. As demonstrated by FIG. 246, the production ofcondensable hydrocarbons in both experiments yielded similar results,even though the particle sizes were dramatically different between thetwo experiments. Production of condensable hydrocarbons wassubstantially complete when the temperature reached about 390° C. Inboth experiments, the condensable hydrocarbons had an API gravity ofabout 37°.

[1952] As shown in FIG. 245, methane started to be produced attemperatures at or above about 270° C. Since the experiments wereconducted at atmospheric pressure, it is believed that the methane isproduced from pyrolysis, and not from mere desorption. Between about270° C. and about 400° C., condensable hydrocarbons, methane, and H₂were produced, as shown in FIGS. 245, 247, and 246. FIG. 245 shows thatabove a temperature of about 400° C., methane and H₂ continue to beproduced. Above about 450° C., however, methane concentration decreasedin the produced gases whereas the produced gases contained increasedamounts of H₂. If heating were continued, eventually all H₂ remaining inthe coal would be depleted, and production of gas from the coal wouldcease. FIGS. 245-246 indicate that the ratio of a yield of gas to ayield of condensable hydrocarbons will increase as the temperatureincreases above about 390° C.

[1953] FIGS. 245-246 demonstrate that particle size did notsubstantially affect the quality of condensable hydrocarbons producedfrom the treated coal, the quantity of condensable hydrocarbons producedfrom the treated coal, the amount of gas produced from the treated coal,the composition of the gas produced from the treated coal, the timerequired to produce the condensable hydrocarbons and gas from thetreated coal, or the temperatures required to produce the condensablehydrocarbons and gas from the treated coal. In essence, a block of coalyielded substantially the same results from treatment as small particlesof coal. As such, it is believed that scale-up issues when treating coalwill not substantially affect treatment results. In addition, the acidnumber for the treated coal was found to be 0.04 mg/gram KOH atatmospheric pressure.

[1954] An experiment was conducted to determine an effect of heating onthermal conductivity and thermal diffusivity of a portion of a coalformation. Thermal pulse tests performed in situ in a high volatilebituminous C coal at a field pilot site showed a thermal conductivitybetween 2.0×10⁻³ and 2.39×10⁻³ cal/cm sec ° C. (0.85 and 1.0 W/(m ° K))at 20° C. Ranges in these values were due to different measurementsbetween different wells. The thermal diffusivity was about 4.8×10⁻³cm²/s at 20° C. (the range was from about 4.1×10⁻³ to about 5.7×10⁻³cm²/s at 20° C.). It is believed that these measured values for thermalconductivity and thermal diffusivity are substantially higher than wouldbe expected based on literature sources (e.g., about three times higherin many instances).

[1955] An initial value for thermal conductivity from the in situexperiment is plotted versus temperature in FIG. 248 (this initial valueis point 2048 in FIG. 248). Additional points for thermal conductivity(i.e., all of the other values for line 2050 shown in FIG. 248) wereassessed by calculating thermal conductivities using temperaturemeasurements in all of the wells shown in FIG. 249, total heat inputfrom all heaters shown in FIG. 249, measured heat capacity and densityfor the coal being treated, gas and liquids production data (e.g.,composition, quantity, etc.), etc. For comparison, these assessedthermal conductivity values (see line 2050) were plotted with datareported in two papers from S. Badzioch et al. (1964) and R. E. Glass(1984) (see line 2052). As illustrated in FIG. 248, the assessed thermalconductivities from the in situ experiment were higher than reportedvalues for thermal conductivities. The difference may be at leastpartially accounted for if it is assumed that the reported values do nottake into consideration the confined nature of the coal in an in situapplication. Because the reported values for thermal conductivity ofcoal are relatively low, they discourage the use of in situ heating forcoal.

[1956]FIG. 248 illustrates a decrease in assessed thermal conductivityvalues (line 2050) at about 100° C. It is believed that this decrease inthermal conductivity was caused by water vaporizing in the cracks andvoid spaces (water vapor has a lower thermal conductivity than liquidwater). At about 350° C., the thermal conductivity began to increase,and it increased substantially as the temperature increased to 700° C.It is believed that the increases in thermal conductivity were theresult of molecular changes in the carbon structure. As the carbon washeated it became more graphitic, which is illustrated in TABLE 22 by anincreased vitrinite reflectance after pyrolysis. As void spacesincreased due to fluid production, heat was increasingly transferred byradiation and/or convection. In addition, concentration of hydrogen inthe void spaces was raised due to pyrolysis reactions. Generation ofsynthesis gas may also increase the concentration of hydrogen in voidspaces if a synthesis gas generating fluid is present at elevatedtemperatures.

[1957] Three data points 2054 of thermal conductivities under highstress were derived from laboratory tests on the same high volatilebituminous C coal used for the in situ field pilot site (see FIG. 248).In the laboratory tests, a sample of such coal was stressed from alldirections, and heated relatively quickly. The thermal conductivitieswere determined at higher stress (i.e., 27.6 bars absolute), as comparedto the stress in the in situ field pilot (about 3 bars absolute). Thethree data points 2054 of thermal conductivity values demonstrate thatthe application of stress increased the thermal conductivity of the coalat temperatures of 150° C., 250° C., and 350° C. It is believed thathigher thermal conductivity values were obtained from stressed coalbecause the stress closed at least some cracks/void spaces and/orprevented new cracks/void spaces from forming.

[1958] Using the reported values for thermal conductivity and thermaldiffusivity of coal and a 12 m heat source spacing on an equilateraltriangle pattern, calculations show that a heating period of about tenyears would be needed to raise an average temperature of coal to about350° C. Such a heating period may not be economically viable. Usingexperimental values for thermal conductivity and thermal diffusivity andthe same 12 m heat source spacing, calculations show that the heatingperiod to reach an average temperature of 350° C. would be about 3years. The elimination of about 7 years of heating a formation maysignificantly improve the economic viability of an in situ conversionprocess for coal.

[1959] Molecular hydrogen has a relatively high thermal conductivity(e.g., the thermal conductivity of molecular hydrogen is about 6 timesthe thermal conductivity of nitrogen or air). Therefore, it is believedthat as the amount of hydrogen in the formation void spaces increases,the thermal conductivity of the formation will also increase. Theincrease in thermal conductivity due to the presence of hydrogen in thevoid spaces somewhat offsets decrease in thermal conductivity caused bythe void spaces themselves. It is believed that increase in thermalconductivity due to the presence of hydrogen will be larger for coalformations as compared to other hydrocarbon containing formations sincethe amount of void spaces created during pyrolysis will be larger (i.e.,coal has a higher hydrocarbon density, so pyrolysis and removal offormation fluid from the formation may create more void spaces in coal).

[1960] Hydrocarbon fluids were produced from a portion of a coalformation by an in situ experiment conducted in a portion of a coalformation. The coal was high volatile bituminous C coal. The formationwas heated with electric heaters. FIG. 250 depicts a cross-sectionalrepresentation of the in situ experimental field test system. As shownin FIG. 250, the experimental field test system included coal formation2056 within the ground and grout wall 2058. Coal formation 2056 dippedat an angle of approximately 36° with a thickness of approximately 4.9m. FIG. 249 illustrates a location of heater wells 520A, 520B, 520C,production wells 512A, 512B, and temperature observation wells 1976A,1976B, 1976C, 1976D used for the experimental field test system. Thethree heat sources were disposed in a triangular configuration.Production well 512A was located proximate a center of the heat sourcepattern and equidistant from each of the heat sources. Second productionwell 512B was located outside the heat source pattern and spacedequidistant from the two closest heat sources. Grout wall 2058 wasformed around the heat source pattern and the production wells. Thegrout wall was formed of 24 pillars. Grout wall 2058 inhibited an influxof water into the portion during the in situ experiment. In addition,grout wall 2058 inhibited loss of generated hydrocarbon fluids to anunheated portion of the formation.

[1961] Temperatures were measured at various times during the experimentat each of four temperature observation wells 1976A, 1976B, 1976C, 1976Dlocated within and outside of the heat source pattern as shown in FIG.249. The temperatures measured at each of the temperature observationwells are displayed in FIG. 251 as a function of time. Temperatures atobservation wells 1976A, 1976B, and 1976C were relatively close to eachother. A temperature at temperature observation well 1976D wassignificantly colder. This temperature observation well was locatedoutside of the heater well triangle illustrated in FIG. 249. This datademonstrates that in zones where there was little superposition of heat,temperatures were significantly lower. FIG. 252 illustrates temperatureprofiles measured at heater wells 520A, 520B, and 520C. The temperatureprofiles were relatively uniform at the heat sources. Data points 2057correspond to heater well 520A. Data points 2059 correspond to heaterwell 520B. Data points 2061 correspond to heater well 520C.

[1962]FIG. 253 illustrates a plot of cumulative volume (m³) of liquidhydrocarbons produced 2060 as a function of time (days). FIG. 254illustrates a plot of cumulative volume of gas produced 2062 in standardcubic feet, produced as a function of time (in days) for the same insitu experiment. Both FIG. 253 and FIG. 254 show the results during thepyrolysis stage only of the in situ experiment.

[1963]FIG. 255 illustrates the carbon number distribution of condensablehydrocarbons that were produced using a slow, low temperature retortingprocess. Relatively high quality products were produced duringtreatment. The results in FIG. 255 are consistent with the results setforth in FIG. 256, which show results from heating coal from the sameformation in the laboratory for similar ranges of heating rates as wereused in situ.

[1964] TABLE 22 tabulates analysis results of coal before and afterbeing subjected to thermal treatment (including heating pyrolysis andproduction of synthesis gas). The coal was cored from formation about11-11.3 m below the surface and midway into the coal bed, in both the“before treatment” and “after treatment” samples. Both cores were takenat about the same location. Both cores were taken about 0.66 m from well520C (between the grout wall and well 520C) shown in FIG. 249. In thefollowing TABLE 22 “FA” is the Fischer Assay, “as rec'd” means thesample was tested as it was received and without any further treatment,“Py-Water” is the water produced during pyrolysis, “H/C Atomic Ratio” isthe atomic ratio of hydrogen to carbon, “daf” means “dry ash free,”“dmmf” means “dry mineral matter free,” and “mmf” means “mineral matterfree.” The specific gravity of the “after treatment” core sample wasapproximately 0.85 whereas the specific gravity of the “beforetreatment” core sample was approximately 1.35. TABLE 22 Before AfterAnalysis Treatment Treatment % Vitrinite Reflectance 0.54 5.16 FA(gal/ton, as-rec'd) 11.81 0.17 FA (wt %, as rec'd) 6.10 0.61 FA Py-Water(gal/ton, as-rec'd) 10.54 2.22 H/C Atomic Ratio 0.85 0.06 H (wt %, daf)5.31 0.44 O (wt %, daf) 17.08 3.06 N (wt %, daf) 1.43 1.35 Ash (wt %, asrec'd) 32.72 56.50 Fixed Carbon (wt %, dmmf) 54.45 94.43 Volatile Matter(wt %, dmmf) 45.55 5.57 Heating Value (Btu/lb, moist, mmf) 12048 14281

[1965] Even though the cores were taken outside the areas within thetriangle formed by the three heaters in FIG. 249, the cores demonstratethat the coal remaining in the formation changed significantly duringtreatment. The vitrinite reflectance results shown in TABLE 22demonstrate that the rank of the coal remaining in the formationincreased substantially during treatment. The coal was a high volatilebituminous C coal before treatment. After treatment, however, the coalwas essentially anthracite. The Fischer Assay results shown in TABLE 22demonstrate that most of the hydrocarbons in the coal had been removedduring treatment. The H/C Atomic Ratio demonstrates that most of thehydrogen in the coal had been removed during treatment. A significantamount of nitrogen and ash was left in the formation.

[1966] In sum, the results shown in TABLE 22 demonstrate that asignificant amount of hydrocarbons and hydrogen were removed duringtreatment of the coal by pyrolysis and generation of synthesis gas.Significant amounts of undesirable products (ash and nitrogen) remain inthe formation, while significant amounts of desirable products (e.g.,condensable hydrocarbons and gas) were removed.

[1967]FIG. 257 illustrates a plot of weight percent of a hydrocarbonproduced versus carbon number distribution for two laboratoryexperiments on coal from the field experiment site. The coal was a highvolatile bituminous C coal. As shown in FIG. 257, a carbon numberdistribution of fluids produced from a formation varied depending onpressure. For example, first pressure 2064 was about 1 bar absolute andsecond pressure 2066 was about 8 bars absolute. The laboratory carbonnumber distribution shown in FIG. 257 was similar to that produced inthe field experiment in FIG. 255 also at 1 bar absolute. As shown inFIG. 257, as pressure increased, a range of carbon numbers of thehydrocarbon fluids decreased. An increase in products having carbonnumbers less than 20 was observed when operating at 8 bars absolute.Increasing the pressure from 1 bar absolute to 8 bars absolute alsoincreased an API gravity of the condensed hydrocarbon fluids. The APIgravities of condensed hydrocarbon fluids produced were approximately23.1° and approximately 31.3°, respectively. The increase in API gravitymay represent a corresponding increase in the value of the product.

[1968]FIG. 258 illustrates a bar graph of fractions from a boiling pointseparation of hydrocarbon liquids generated by a Fischer Assay (hatchedbars) and a boiling point separation (solid bars) of hydrocarbon liquidsfrom the coal cube experiment (see, e.g., the system shown in FIG. 243).The experiment was conducted at a much slower heating rate (2° C./day)and the oil produced at a lower final temperature than the FischerAssay. FIG. 258 shows the weight percent of various boiling point cutsof hydrocarbon liquids produced from a Fruitland high volatilebituminous B coal. Different boiling point cuts may represent differenthydrocarbon fluid compositions. The boiling point cuts illustratedinclude naphtha 2068 (initial boiling point to 166° C.), jet fuel 2070(166° C. to 249° C.), diesel 2072 (249° C. to 370° C.), and bottoms 2074(boiling point greater than 370° C.). The hydrocarbon liquids from thecoal cube were products that are more valuable. The API gravity of suchhydrocarbon liquids was significantly greater than the API gravity ofthe Fischer Assay liquid. The hydrocarbon liquids from the coal cubealso included significantly less residual bottoms than were producedfrom the Fischer Assay hydrocarbon liquids.

[1969]FIG. 259 illustrates a plot of percentage ethene to ethaneproduced from a coal formation as a function of heating rate. Datapoints were derived from laboratory experimental data (see system shownin FIG. 202 and associated text) for slow heating of high volatilebituminous C coal at atmospheric pressure, and from Fischer Assayresults. As illustrated in FIG. 259, the ratio of ethene to ethaneincreased as the heating rate increased. Decreasing the heating rate ofa formation may decrease production of olefins. The heating rate of aformation may be determined in part by the spacings of heat sourceswithin the formation, and by the amount of heat that is transferred fromthe heat sources to the formation.

[1970] Formation pressure may also have a significant effect on olefinproduction. A high formation pressure may result in the production ofsmall quantities of olefins. High pressure within a formation may resultin a high H₂ partial pressure within the formation. The high H₂ partialpressure may result in hydrogenation of the fluid within the formation.Hydrogenation may result in a reduction of olefins in a fluid producedfrom the formation. A high pressure and high H₂ partial pressure mayalso result in inhibition of aromatization of hydrocarbons within theformation. Aromatization may include formation of aromatic and cycliccompounds from alkanes and/or alkenes within a hydrocarbon mixture. Ifit is desirable to increase production of olefins from a formation, theolefin content of fluid produced from the formation may be increased byreducing pressure within the formation. The pressure may be reduced bydrawing off a larger quantity of formation fluid from a portion of theformation that is being produced. In some in situ conversion processembodiments, pressure within a formation adjacent to production wellsmay be reduced below atmospheric pressure (i.e., a vacuum may be drawnon the formation).

[1971] The system depicted in FIG. 202, and the method of using thesystem was used to conduct experiments on high volatile bituminous Ccoal. The coal was heated at a rate of 5° C./day at atmosphericpressure. FIG. 260 depicts certain data points from the experiment (theline depicted in FIG. 260 was produced from a linear regression analysisof the data points). FIG. 260 illustrates the ethene to ethane molarratio as a function of hydrogen molar concentration in non-condensablehydrocarbons produced from the coal during the experiment. The ethene toethane ratio in the non-condensable hydrocarbons is reflective of olefincontent in all hydrocarbons produced from the coal. As can be seen inFIG. 260, as the concentration of hydrogen autogenously increased duringpyrolysis, the ratio of ethene to ethane decreased. It is believed thatincreases in the concentration (and partial pressure) of hydrogen duringpyrolysis causes the olefin concentration to decrease in the fluidsproduced from pyrolysis.

[1972]FIG. 261 illustrates product quality, as measured by API gravity,as a function of rate of temperature increase of fluids produced fromhigh volatile bituminous “C” coal. Data points were derived from FischerAssay data and from laboratory experiments. For the Fischer Assay data,the rate of temperature increase was approximately 17,100° C./day andthe resulting API gravity was less than 11°. For the relatively slowlaboratory experiments, the rate of temperature increase ranged fromabout 2° C./day to about 10° C./day, and the resulting API gravitiesranged from about 23° to about 26°. A substantially linear decrease inquality (decrease in API gravity) was exhibited as the logarithmicheating rate increased.

[1973]FIG. 256 illustrates weight percentages of various carbon numbersproducts removed from high volatile bituminous “C” coal when coal isheated at various heating rates. Data points were derived fromlaboratory experiments and a Fischer Assay. Curves for heating at a rateof 2° C./day 2076, 3° C./day 2078, 5° C./day 2080, and 10° C./day 2082show carbon number distributions in the produced fluids. A coal samplewas also heated in a Fischer Assay test at a rate of about 17,100°C./day. The data from the Fischer Assay test is indicated by referencenumeral 2084. Slow heating rates resulted in less production ofcomponents having carbon numbers greater than 20 as compared to FischerAssay results 2084. Lower heating rates also produced higher weightpercentages of components with carbon numbers less than 20. The lowerheating rates produced large amounts of components having carbon numbersnear 12. A peak in carbon number distribution near 12 is typical of thein situ conversion process for coal and oil shale.

[1974] An experiment was conducted on the coal formation treated by anin situ conversion process to measure the permeability of the formationafter pyrolysis. After heating a portion of the coal formation, a tenminute pulse of CO₂ was injected into the formation at first productionwell 512A and produced at wells 520A, 520B and 520C (shown in FIG. 249).Wells 520A, 520B, 520C were located substantially equidistant from theproduction well in a triangular pattern. The CO₂ was injected at a rateof 4.08 m³/h (144 standard cubic feet per hour). As illustrated in FIG.262, the CO₂ reached each of the three different heat sources atapproximately the same time. Line 2086 illustrates production of CO₂ atheater well 520A, line 2088 illustrates production of CO₂ at heater well520B, and line 2090 illustrates production of CO₂ at heater well 520C.As shown in FIG. 262, yield of CO₂ from each of the three differentwells was also approximately equal over time. Such approximatelyequivalent transfer of a tracer pulse of CO₂ through the formation andyield of CO₂ from the formation indicated that the formation wassubstantially uniformly permeable. The fact that the first CO₂ arrivalat wells 520A, 520B, 520C after approximately 18 minutes after start ofthe CO₂ pulse indicates that no preferential paths had been createdbetween production well 512 and wells 520A, 520B, and 520C.

[1975] The in situ permeability was measured by injecting a gas betweendifferent wells after the pyrolysis and synthesis gas formation stageswere complete. The measured permeability varied from about 4.5 darcy to39 darcy (with an average of about 20 darcy), thereby indicating thatthe permeability was high and relatively uniform. The before-treatmentpermeability was only about 50 millidarcy.

[1976] Synthesis gas was also produced in an in situ experiment from theportion of the coal formation shown in FIG. 250 and FIG. 249. In thisexperiment, heater wells were used to inject fluids into the formation.FIG. 263 is a plot of weight of volatiles (condensable anduncondensable) in kilograms as a function of cumulative energy contentof product in kilowatt hours from the in situ experimental field test.The figure illustrates the quantity and energy content of pyrolysisfluids and synthesis gas produced from the formation.

[1977]FIG. 264 is a plot of the volume of oil equivalent produced (m³)as a function of energy input into the coal formation (kW·h) from theexperimental field test. The volume of oil equivalent in cubic meterswas determined by converting the energy content of the volume ofproduced oil plus gas to a volume of oil with the same energy content.

[1978] The start of synthesis gas production, indicated by arrow 2092,was at an energy input of approximately 77,000 kW·h. The average coaltemperature in the pyrolysis region had been raised to 620° C. Becausethe average slope of the curve in FIG. 264 in the pyrolysis region isgreater than the average slope of the curve in the synthesis gas region,FIG. 264 illustrates that the amount of useable energy contained in theproduced synthesis gas is less than that contained in the pyrolysisfluids. Therefore, synthesis gas production is less energy efficientthan pyrolysis. There are two reasons for this result. First, the two H₂molecules produced in the synthesis gas reaction have a lower energycontent than low carbon number hydrocarbons produced in pyrolysis.Second, endothermic synthesis gas reactions consume energy.

[1979]FIG. 265 is a plot of the total synthesis gas production (m³/min)from the coal formation versus the total water inflow (kg/h) due toinjection into the formation from the experimental field test resultsfacility. Synthesis gas may be generated in a formation at a synthesisgas generating temperature before the injection of water or steam due tothe presence of natural water inflow into hot coal formation. Naturalwater may come from below the formation.

[1980] From FIG. 265, the maximum natural water inflow is approximately5 kg/h as indicated by arrow 2094. Arrows 2096, 2098, and 2100 representinjected water rates of about 2.7 kg/h, 5.4 kg/h, and 11 kg/h,respectively, into central well 512A of FIG. 249. Production ofsynthesis gas is at heater wells 520A, 520B, and 520C. FIG. 265 showsthat the synthesis gas production per unit volume of water injecteddecreases at arrow 2096 at approximately 2.7 kg/h of injected water or7.7 kg/h of total water inflow. The reason for the decrease may be thatsteam is flowing too fast through the coal seam to allow the reactionsto approach equilibrium conditions.

[1981]FIG. 266 illustrates production rate of synthesis gas (m³/min) asa function of steam injection rate (kg/h) in a coal formation. Data 2102for a first run corresponds to injection at production well 512A in FIG.249 and production of synthesis gas at heater wells 520A, 520B, and520C. Data 2104 for a second run corresponds to injection of steam atheater well 520C and production of additional gas at production well512A. Data 2102 for the first run corresponds to the data shown in FIG.265. As shown in FIG. 266, the injected water is in reaction equilibriumwith the formation to about 2.7 kg/h of injected water. The second runresults in substantially the same amount of additional synthesis gasproduced, shown by data 2104, as the first run to about 1.2 kg/h ofinjected steam. At about 1.2 kg/h, data 2102 starts to deviate fromequilibrium conditions because the residence time is insufficient forthe additional water to react with the coal. As temperature isincreased, a greater amount of additional synthesis gas is produced fora given injected water rate. The reason is that at higher temperaturesthe reaction rate and conversion of water into synthesis gas increases.

[1982]FIG. 267 is a plot that illustrates the effect of methaneinjection into a heated coal formation in the experimental field test(all of the units in FIGS. 267-270 are in m³ per hour). FIG. 267demonstrates hydrocarbons added to the synthesis gas producing fluid arecracked within the formation. FIG. 249 illustrates the layout of theheater and production wells at the field test facility. Methane wasinjected into production wells 512A and 512B and fluid was produced fromheater wells 520A, 520B, and 520C. The average temperatures at variouswells were as follows: 520A (746° C.), 520B (746° C.), 520C (767° C.),1976A (592° C.), 1976B (573° C.), 1976C (606° C.), and 512A (769° C.).When the methane contacted the formation, a portion of the methanecracked within the formation to produce H₂ and coke. FIG. 267 shows thatas the methane injection rate increased, the production of H₂ 2028increased. This indicated that methane was cracking to form H₂.Production of methane 2030 also increased, which indicates that not allof the injected methane is cracked. The measured compositions of ethane,ethene, propane, and butane were negligible.

[1983]FIG. 268 is a plot that illustrates the effect of ethane injectioninto a heated coal formation in the experimental field test. Ethane wasinjected into production wells 512A and 512B and fluid was produced fromheater wells 520A, 520B, and 520C in FIG. 249. The average temperaturesat various wells were as follows: 520A (742° C.), 520B (750° C.), 520C(744° C.), 1976A (611° C.), 1976B (595° C.), 1976C (626° C.), and 512A(818° C.). When ethane contacted the formation, it cracked to produceH₂, methane, ethene, and coke. FIG. 268 shows that as the ethaneinjection rate increased, the production of H₂ 2028, methane 2030,ethane 2032, and ethene 2106 increased. This indicates that ethane iscracking to form H₂ and low molecular weight hydrocarbons. Theproduction rate of higher carbon number products (i.e., propane andpropylene) were unaffected by the injection of ethane.

[1984]FIG. 269 is a plot that illustrates the effect of propaneinjection into a heated coal formation in the experimental field test.Propane was injected into production wells 512A and 512B and fluid wasproduced from heater wells 520A, 520B, and 520C. The averagetemperatures at various wells were as follows: 520A (737° C.), 520B(753° C.), 520C (726° C.), 1976A (589° C.), 1976B (573° C.), 1976C (606°C.), and 512A (769° C.). When propane contacted the formation, itcracked to produce H₂, methane, ethane, ethene, propylene, and coke.FIG. 269 shows that as the propane injection rate increased, theproduction of H₂ 2028, methane 2030, ethane 2032, ethene 2106, propane2034, and propylene 2108 increased. This indicates that propane iscracking to form H₂ and lower molecular weight components.

[1985]FIG. 270 is a plot that illustrates the effect of butane injectioninto a heated coal formation in the experimental field test. Butane wasinjected into production wells 512A and 512B and fluid was produced fromheater wells 520A, 520B, and 520C. The average temperature at variouswells were as follows: 520A (772° C.), 520B (764° C.), 520C (753° C.),1976A (650° C.), 1976B (591° C.), 1976C (624° C.), and 512A (830° C.).When butane contacted the formation, it cracked to produce H₂, methane,ethane, ethene, propane, propylene, and coke. FIG. 270 shows that as thebutane injection rate increased, the production of H₂ 2028, methane2030, ethane 2032, and ethene 2106 increased. The production of propane2034 and propylene 2108 did not appear to increase. This indicates thatbutane is cracking to form H₂ and lower molecular weight components.

[1986]FIG. 271 is a plot of the composition of gas (in mole percent)produced from the heated coal formation versus time in days at theexperimental field test. The species compositions included methane 2030,H₂ 2028, carbon dioxide 2110, hydrogen sulfide 2114, and carbon monoxide2112. FIG. 271 shows a dramatic increase in H₂ concentration after about150 days. The increase corresponds to the start of synthesis gasproduction.

[1987]FIG. 272 is a plot of synthesis gas conversion versus time forsynthesis gas generation runs in the experimental field test performedon separate days. The temperature of the formation was about 600° C. Thedata demonstrates initial uncertainty in measurements in the oil/waterseparator. Synthesis gas conversion consistently approached a conversionof between about 40% and 50% after about 2 hours of synthesis gasproducing fluid injection.

[1988] TABLE 23 shows a composition of synthesis gas produced during arun of the in situ coal field experiment. TABLE 23 Component Mol % Wt %Methane 12.263 12.197 Ethane 0.281 0.525 Ethene 0.184 0.320 Acetylene0.000 0.000 Propane 0.017 0.046 Propylene 0.026 0.067 Propadiene 0.0010.004 Isobutane 0.001 0.004 n-Butane 0.000 0.001 l-Butene 0.001 0.003Isobutene 0.000 0.000 cis-2-Butene 0.005 0.018 trans-2-Butene 0.0010.003 1,3-Butadiene 0.001 0.005 Isopentane 0.001 0.002 n-Pentane 0.0000.002 Pentene-1 0.000 0.000 T-2-Pentene 0.000 0.000 2-Methyl-2-Butene0.000 0.000 C-2-Pentene 0.000 0.000 Hexanes 0.081 0.433 H₂ 51.247 6.405Carbon monoxide 11.556 20.067 Carbon dioxide 17.520 47.799 Nitrogen5.782 10.041 Oxygen 0.955 1.895 Hydrogen sulfide 0.077 0.163 Total100.000 100.000

[1989] The experiment was performed in batch oxidation mode at about620° C. The presence of nitrogen and oxygen is due to contamination ofthe sample with air. The mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, may bedetermined for the above data. For example, mole percent of H₂, carbonmonoxide, and carbon dioxide may be increased proportionally such thatthe mole percentages of the three components equals approximately 100%.The mole percent of H₂, carbon monoxide, and carbon dioxide, neglectingthe composition of all other species, were 63.8%, 14.4%, and 21.8%,respectively. The methane is believed to come primarily from thepyrolysis region outside the triangle of heaters. These values are insubstantial agreement with the equilibrium values shown in FIG. 273.

[1990]FIG. 273 is a plot of calculated equilibrium gas dry molefractions for a coal reaction with water. Methane reactions are notincluded. The fractions are representative of a synthesis gas producedfrom a hydrocarbon containing formation and has been passed through acondenser to remove water from the produced gas. Equilibrium gas drymole fractions are shown in FIG. 273 for H₂ 2028, carbon monoxide 2112,and carbon dioxide 2110 as a function of temperature at a pressure of 2bars absolute. Liquid production from a formation substantially stops attemperatures of about 390° C. Gas produced at about 390° C. includesabout 67% H₂ and about 33% carbon dioxide. Carbon monoxide is present innegligible quantities below about 410° C. At temperatures of about 500°C., however, carbon monoxide is present in the produced gas inmeasurable quantities. For example, at 500° C., about 66.5% H₂, about32% carbon dioxide, and about 2.5% carbon monoxide are present. At 700°C., the produced gas includes about 57.5% H₂, about 15.5% carbondioxide, and about 27% carbon monoxide.

[1991]FIG. 274 is a plot of calculated equilibrium wet mole fractionsfor a coal reaction with water. Methane reactions are not included.Equilibrium wet mole fractions are shown for water 2116, H₂ 2028, carbonmonoxide 2112, and carbon dioxide 2110 as a function of temperature at apressure of 2 bars absolute. At 390° C., the produced gas includes about89% water, about 7% H₂, and about 4% carbon dioxide. At 500° C., theproduced gas includes about 66% water, about 22% H₂, about 11% carbondioxide, and about 1% carbon monoxide. At 700° C., the produced gasincludes about 18% water, about 47.5% H₂, about 12% carbon dioxide, andabout 22.5% carbon monoxide.

[1992]FIG. 273 and FIG. 274 illustrate that at the lower end of thetemperature range at which synthesis gas may be produced (i.e., about400° C.), equilibrium gas phase fractions may not favor production of H₂within and from a formation. As temperature increases, the equilibriumgas phase fractions increasingly favor the production of H₂. Forexample, as shown in FIG. 274, the gas phase equilibrium wet molefraction of H₂ increases from about 9% at 400° C. to about 39% at 610°C. and reaches 50% at about 800° C. FIG. 273 and FIG. 274 furtherillustrate that at temperatures greater than about 660° C., equilibriumgas phase fractions tend to favor production of carbon monoxide overcarbon dioxide.

[1993]FIG. 273 and FIG. 274 illustrate that as the temperature increasesfrom between about 400° C. to about 1000° C., the H₂ to carbon monoxideratio of produced synthesis gas may continuously decrease throughoutthis range. For example, as shown in FIG. 274, the equilibrium gas phaseH₂ to carbon monoxide ratio at 500° C., 660° C., and 1000° C. is about22:1, about 3:1, and about 1:1, respectively. FIG. 274 also indicatesthat produced synthesis gas at lower temperatures may have a largerquantity of water and carbon dioxide than at higher temperatures. As thetemperature increases, the overall percentage of carbon monoxide andhydrogen within the synthesis gas may increase.

[1994]FIG. 275 is a flow chart of an example of pyrolysis stage 2118 andsynthesis gas production stage 2120 for a high volatile type A or Bbituminous coal. In pyrolysis stage 2118, heat 2122A is supplied to coalformation 2056. Liquid and gas products 2124 and water 1524 exit coalformation 2056. The portion of the formation subjected to pyrolysis iscomposed substantially of char after undergoing pyrolysis heating. Charrefers to a solid carbonaceous residue that results from pyrolysis oforganic material. In synthesis gas production stage 2120, steam 1392 andheat 2122B are supplied to formation 678 that has undergone pyrolysis,and synthesis gas 1502 is produced.

[1995] Heat and mass balances may be performed for the processesdepicted in FIG. 275. The calculations set forth herein assume that charis only made of carbon and that there is an excess of carbon to steam.About 890 MW (megawatts) of energy is required to pyrolyze about 105,800metric tons per day of coal. Pyrolysis products 2124 include liquids andgases with a production of 23,000 cubic meters per day. The pyrolysisprocess also produces about 7,160 metric tons per day of water 1524. Inthe synthesis gas stage about 57,800 metric tons per day of char withinjection of 23,000 metric tons per day of steam 1392 and 2,000 MW ofenergy 2122B with a 20% conversion will produce 12,700 cubic metersequivalent oil per day of synthesis gas 1502. The energy balance aboveincludes the methane reactions in EQNS. (57) and (58).

[1996]FIG. 276 is an example of a low temperature in situ synthesis gasproduction that occurs at a temperature of about 450° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 42,900 metric tons per day of water isinjected into formation 678 which may be char. FIG. 276 illustrates thata portion of water 1524 at 25° C. is injected directly into formation678. A portion of water 1524 is converted into steam 1392A at atemperature of about 130° C. and a pressure at about 3 bars absoluteusing about 1227 MW of energy 2126A and injected into formation 678. Aportion of the remaining steam may be converted into steam 1392B at atemperature of about 450° C. and a pressure at about 3 bars absoluteusing about 318 MW of energy 2126B. The synthesis gas productioninvolves about 23% conversion of 13,137 metric tons per day of char toproduce 56.6 millions of cubic meters per day of synthesis gas with anenergy content of 5,230 MW. About 238 MW of energy 2126C is supplied toformation 678 to account for the endothermic heat of reaction of thesynthesis gas reaction. Product stream 1590 of the synthesis gasreaction includes 29,470 metric tons per day of water at 46 volume %,501 metric tons per day carbon monoxide at 0.7 volume %, 540 tons perday H₂ at 10.7 volume %, 26,455 metric tons per day carbon dioxide at23.8 volume %, and 7,610 metric tons per day methane at 18.8 volume %.

[1997]FIG. 277 is an example of a high temperature in situ synthesis gasproduction that occurs at a temperature of about 650° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 34,352 metric tons per day of water isinjected into formation 678. FIG. 277 illustrates that a portion ofwater 1524 at 25° C. is injected directly into formation 678. A portionof water 1524 is converted into steam 1392A at a temperature of about130° C. and a pressure at about 3 bars absolute using about 982 MW ofenergy 2126A, and injected into formation 678. A portion of theremaining steam is converted into steam 1392B at a temperature of about650° C. and a pressure at about 3 bars absolute using about 413 MW ofenergy 2126B. The synthesis gas production involves about 22% conversionof 12,771 metric tons per day of char to produce 56.6 millions of cubicmeters per day of synthesis gas with an energy content of 5,699 MW.About 898 MW of energy 2126C is supplied to formation 678 to account forthe endothermic heat of reaction of the synthesis gas reaction. Productstream 1590 of the synthesis gas reaction includes 10,413 metric tonsper day of water at 22.8 volume %, 9,988 metric tons per day carbonmonoxide at 14.1 volume %, 1771 metric tons per day H₂ at 35 volume %,21,410 metric tons per day carbon dioxide at 19.3 volume %, and 3535metric tons per day methane at 8.7 volume %.

[1998]FIG. 278 is an example of an in situ synthesis gas production in ahydrocarbon containing formation with heat and mass balances. Synthesisgas generating fluid that includes water 1524 is supplied to formation678. A total of about 22,000 metric tons per day of water is requiredfor a low temperature process and about 24,000 metric tons per day isrequired for a high temperature process. A portion of the water may beintroduced into the formation as steam. Steam may be produced bysupplying heat from an external source to the water. About 7,119 metrictons per day of steam is provided for the low temperature process andabout 6913 metric tons per day of steam is provided for the hightemperature process.

[1999] At least a portion of aqueous fluid 2128 exiting formation 678 isrecycled 2130 back into the formation for generation of synthesis gas.For a low temperature process about 21,000 metric tons per day ofaqueous fluids is recycled and for a high temperature process about10,000 metric tons per day of aqueous fluids is recycled. Producedsynthesis gas 1502 includes carbon monoxide, H₂, and methane. Theproduced synthesis gas has a heat content of about 430,000 MMBtu(millions Btu) per day for a low temperature process and a heat contentof about 470,000 MMBtu per day for a low temperature process. Carbondioxide 2129 produced in the synthesis gas process includes about 26,500metric tons per day in the low temperature process and about 21,500metric tons per day in the high temperature process. At least a portionof produced synthesis gas 1502 is used for combustion to heat theformation. There is about 7,119 metric tons per day of carbon dioxide insteam for the low temperature process and about 6,913 metric tons perday of carbon dioxide in the steam for the high temperature process.There are about 2,551 metric tons per day of carbon dioxide in a heatreservoir for the low temperature process and about 9,628 metric tonsper day of carbon dioxide in a heat reservoir for the high temperatureprocess. There are about 14,571 metric tons per day of carbon dioxide inthe combustion of synthesis gas for the low temperature process andabout 18,503 metric tons per day of carbon dioxide in producedcombustion synthesis gas for the high temperature process. The producedcarbon dioxide has a heat content of about 60 gigaJoules (“GJ”) permetric ton for the low temperature process and about 6.3 GJ per metricton for the high temperature process.

[2000] TABLE 24 is an overview of the potential production volume ofapplications of synthesis gas produced by wet oxidation. The estimatesare based on 56.6 million standard cubic meters of synthesis gasproduced per day at 700° C. TABLE 24 Production (main Applicationproduct) Power  2,720 Megawatts Hydrogen  2,700 metric tons/day NH₃13,800 metric tons/day CH₄  7,600 metric tons/day Methanol 13,300 metrictons/day Shell Middle  5,300 metric tons/day Distillates

[2001] Experimental adsorption data has demonstrated that carbon dioxidemay be stored in coal that has been pyrolyzed. FIG. 279 is a plot of thecumulative sorbed methane and carbon dioxide in cubic meters per metricton versus pressure in bars absolute at 25° C. on coal. The coal sampleis sub-bituminous coal from Gillette, Wyo. Data sets 2132B, 2132C,2132D, and 2132E are for carbon dioxide adsorption on a post treatmentcoal sample that has been pyrolyzed and has undergone synthesis gasgeneration. Data set 2132F is for adsorption on an unpyrolyzed coalsample from the same formation. Data set 2132A is adsorption of methaneat 25° C. Data sets 2132B, 2132C, 2132D, and 2132E are adsorption ofcarbon dioxide at 25° C., 50° C., 100° C., and 150° C., respectively.Data set 2132F is adsorption of carbon dioxide at 25° C. on theunpyrolyzed coal sample. FIG. 279 shows that carbon dioxide attemperatures between 25° C. and 100° C. is more strongly adsorbed thanmethane at 25° C. in the pyrolyzed coal. FIG. 279 demonstrates that acarbon dioxide stream passed through post treatment coal tends todisplace methane from the post treatment coal.

[2002] Computer simulations have demonstrated that carbon dioxide may besequestered in both a deep coal formation and a post treatment coalformation. The Comet2™ Simulator (Advanced Resources International,Houston, Tex.) determined the amount of carbon dioxide that could besequestered in a San Juan Basin type deep coal formation and a posttreatment coal formation. The simulator also determined the amount ofmethane produced from the San Juan Basin type deep coal formation due tocarbon dioxide injection. The model employed for both the deep coalformation and the post treatment coal formation was a 1.3 km² area, witha repeating 5 spot well pattern. The 5 spot well pattern included fourinjection wells arranged in a square and one production well at thecenter of the square. The properties of the San Juan Basin and the posttreatment coal formations are shown in TABLE 25. Additional details ofsimulations of carbon dioxide sequestration in deep coal formations andcomparisons with field test results may be found in Pilot TestDemonstrates How Carbon Dioxide Enhances Coal Bed Methane Recovery,Lanny Schoeling and Michael McGovern, Petroleum Technology Digest,September 2000, p. 14-15. TABLE 25 Post treatment coal Deep CoalFormation formation (Post (San Juan Basin) pyrolysis process CoalThickness (m) 9 9 Coal Depth (m) 990 460 Initial Pressure (bars abs.)114 2 Initial Temperature 25° C. 25° C. Permeability (md) 5.5 (horiz.),10,000 (horiz.), 0 (vertical) 0 (vertical) Cleat porosity 0.2% 40%

[2003] The simulation model accounts for the matrix and dual porositynature of coal and post treatment coal. For example, coal and posttreatment coal are composed of matrix blocks. The spaces between theblocks are called “cleats.” Cleat porosity is a measure of availablespace for flow of fluids in the formation. The relative permeabilitiesof gases and water within the cleats required for the simulation werederived from field data from the San Juan coal. The same values forrelative permeabilities were used in the post treatment coal formationsimulations. Carbon dioxide and methane were assumed to have the samerelative permeability.

[2004] The cleat system of the deep coal formation was modeled asinitially saturated with water. Relative permeability data for carbondioxide and water demonstrate that high water saturation inhibitsabsorption of carbon dioxide within cleats. Therefore, water is removedfrom the formation before injecting carbon dioxide into the formation.

[2005] In addition, the gases within the cleats may adsorb in the coalmatrix. The matrix porosity is a measure of the space available forfluids to adsorb in the matrix. The matrix porosity and surface areawere taken into account with experimental mass transfer and isothermadsorption data for coal and post treatment coal. Therefore, it was notnecessary to specify a value of the matrix porosity and surface area inthe model. The pressure-volume-temperature (PVT) properties andviscosity required for the model were taken from literature data for thepure component gases.

[2006] The preferential adsorption of carbon dioxide over methane onpost treatment coal was incorporated into the model based onexperimental adsorption data. For example, FIG. 279 demonstrates thatcarbon dioxide has a significantly higher cumulative adsorption thanmethane over an entire range of pressures at a specified temperature.Once the carbon dioxide enters in the cleat system, methane diffuses outof and desorbs off the matrix. Similarly, carbon dioxide diffuses intoand adsorbs onto the matrix. In addition, FIG. 279 also shows carbondioxide may have a higher cumulative adsorption on a pyrolyzed coalsample than an unpyrolyzed coal sample.

[2007] The simulation modeled a sequestration process over a time periodof about 3700 days for the deep coal formation model. Removal of thewater in the coal formation was simulated by production from five wells.The production rate of water was about 40 m³/day for about the first 370days. The production rate of water decreased significantly after thefirst 370 days. It continued to decrease through the remainder of thesimulation run to about zero at the end. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard (in this context “standard” means 1 atmosphere pressure and15.5° C.) m³/day. The injection rate of carbon dioxide was doubled toabout 226,000 standard m³/day at approximately 1440 days. The injectionrate remained at about 226,000 standard m³/day until the end of thesimulation run.

[2008]FIG. 280 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation. The pressuredecreased from about 114 bars absolute to about 19 bars absolute overthe first 370 days. The decrease in the pressure was due to removal ofwater from the coal formation. Pressure then started to increasesubstantially as carbon dioxide injection started at 370 days. Thepressure reached a maximum of about 98 bars absolute. The pressure thenbegan to gradually decrease after 480 days. At about 1440 days, thepressure increased again to about 98 bars absolute due to the increasein the carbon dioxide injection rate. The pressure gradually increaseduntil about 3640 days. The pressure jumped at about 3640 days becausethe production well was closed off.

[2009]FIG. 281 illustrates the production rate of carbon dioxide 2110and methane 2030 as a function of time in the simulation. FIG. 281 showsthat carbon dioxide was produced at a rate between about 0-10,000 m³/dayduring approximately the first 2400 days. The production rate of carbondioxide was significantly below the injection rate. Therefore, thesimulation predicts that most of the injected carbon dioxide is beingsequestered in the coal formation. However, at about 2400 days, theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the coal formation.

[2010] In addition, FIG. 281 shows that methane was desorbing as carbondioxide was adsorbing in the coal formation. Between about 370-2400days, the production rate of methane 2030 increased from about 60,000 toabout 115,000 standard m³/day. The increase in the methane productionrate between about 1440-2400 days was caused by the increase in carbondioxide injection rate at about 1440 days. The production rate ofmethane started to decrease after about 2400 days. This was due to thesaturation of the coal formation. The simulation predicted a 50%breakthrough at about 2700 days. “Breakthrough” is defined as the ratioof the flow rate of carbon dioxide to the total flow rate of the totalproduced gas times 100%. In addition, the simulation predicted about a90% breakthrough at about 3600 days.

[2011]FIG. 282 illustrates cumulative methane produced 2134 and thecumulative net carbon dioxide injected 2136 as a function of time duringthe simulation. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 282 shows that by the end of the simulated injection,about twice as much carbon dioxide was stored as methane produced. Inaddition, the methane production was about 0.24 billion standard m³ at50% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.39 billion standard m³ at 50% carbon dioxidebreakthrough. The methane production was about 0.26 billion standard m³at 90% carbon dioxide breakthrough. In addition, the carbon dioxidesequestration was about 0.46 billion standard m³ at 90% carbon dioxidebreakthrough.

[2012] TABLE 25 shows that the permeability and porosity of thesimulation in the post treatment coal formation were both significantlyhigher than in the deep coal formation prior to treatment. In addition,the initial pressure was much lower. The depth of the post treatmentcoal formation was shallower than the deep coal bed methane formation.The same relative permeability data and PVT data used for the deep coalformation were used for the coal formation simulation. The initial watersaturation for the post treatment coal formation was set at 70%. Waterwas present because it is used to cool the hot spent coal formation to25° C. The amount of methane initially stored in the post treatment coalis very low.

[2013] The simulation modeled a sequestration process over a time periodof about 3800 days for the post treatment coal formation model. Thesimulation modeled removal of water from the post treatment coalformation with production from five wells. During about the first 200days, the production rate of water was about 680,000 standard m³/day.From about 200-3300 days, the water production rate was between about210,000 to about 480,000 standard m³/day. Production rate of water wasnegligible after about 3300 days. Carbon dioxide injection was startedat approximately 370 days at a flow rate of about 113,000 standardm³/day. The injection rate of carbon dioxide was increased to about226,000 standard m³/day at approximately 1440 days. The injection rateremained at 226,000 standard m³/day until the end of the simulatedinjection.

[2014]FIG. 283 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation of the post treatmentcoal formation model. The pressure was relatively constant up to about370 days. The pressure increased through most of the rest of thesimulation run up to about 36 bars absolute. The pressure rose steeplystarting at about 3300 days because the production well was closed off.

[2015]FIG. 284 illustrates the production rate of carbon dioxide as afunction of time in the simulation of the post treatment coal formationmodel. FIG. 284 shows that the production rate of carbon dioxide wasalmost negligible during approximately the first 2200 days. Therefore,the simulation predicts that nearly all of the injected carbon dioxideis being sequestered in the post treatment coal formation. However, atabout 2240 days, the produced carbon dioxide began to increase. Theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the post treatment coal formation.

[2016]FIG. 285 illustrates cumulative net carbon dioxide injected as afunction of time during the simulation in the post treatment coalformation model. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 285 shows that the simulation predicts a potential netsequestration of carbon dioxide of 0.56 Bm³. This value is greater thanthe value of 0.46 Bm³ at 90% carbon dioxide breakthrough in the deepcoal formation. However, comparison of FIG. 280 with FIG. 283 shows thatsequestration occurs at much lower pressures in the post treatment coalformation model. Therefore, less compression energy was required forsequestration in the post treatment coal formation.

[2017] The simulations show that large amounts of carbon dioxide may besequestered in both deep coal formations and in post treatment coalformations that have been cooled. Carbon dioxide may be sequestered inthe post treatment coal formation, in coal formations that have not beenpyrolyzed, and/or in both types of formations.

[2018]FIG. 286 is a flow chart of an embodiment of in situ synthesis gasproduction process 2140 integrated with a SMDS Fischer-Tropsch and waxcracking process with heat and mass balances. The synthesis gasgenerating fluid injected into the formation includes about 24,000metric tons per day of water 1524A, which includes about 5,500 metrictons per day of water 1524B recycled from the SMDS Fischer-Tropsch and,wax cracking process 2142. A total of about 1700 MW of energy issupplied to the in situ synthesis gas production process 2140. About1020 MW of energy 2126A of the approximately 1700 MW of energy issupplied by in situ reaction of an oxidizing fluid with the formation,and approximately 680 MW of energy 2126B is supplied by the SMDSFischer-Tropsch and wax cracking process 2142 in the form of steam.About 12,700 cubic meters equivalent oil per day of synthesis gas 1502is used as feed gas to the SMDS Fischer-Tropsch and wax cracking process2142. The SMDS Fischer-Tropsch and wax cracking process 2142 producesabout 4,770 cubic meters per day of products 1444 that may includenaphtha, kerosene, diesel, and about 5,880 cubic meters equivalent oilper day of off gas 2144 for a power generation facility.

[2019]FIG. 287 is a comparison between numerical simulation and the insitu experimental coal field test composition of synthesis gas producedas a function of time. The plot excludes nitrogen and traces of oxygenthat were contaminants during gas sampling. Symbols representexperimental data and curves represent simulation results. Hydrocarbons2150 are methane since all other heavier hydrocarbons have decomposed atthe existing formation temperatures. The simulation results are movingaverages of raw results, which exhibit peaks and troughs ofapproximately ±10 percent of the averaged value. In the model, the peaksof H₂ occurred when fluids were injected into the coal seam, andcoincided with lows in CO₂ and CO.

[2020] The simulation of H₂ 2146 provides a good fit to observedfraction of H₂ 2148. The simulation of methane 2152 provides a good fitto observed fraction of hydrocarbons 2150. The simulation of carbondioxide 2155 provides a good fit to observed fraction of carbon dioxide2153. The simulation of CO 2154 overestimated the fraction of CO 2156 by4-5 percentage points. Carbon monoxide is the most difficult of thesynthesis gas components to model. In addition, the carbon monoxidediscrepancy may be due to fact that the pattern temperatures exceeded550° C., the upper limit at which the numerical model was calibrated.

[2021] Other methods of producing synthesis gas were successfullydemonstrated at the experimental field test. These included continuousinjection of steam and air, steam and oxygen, water and air, water andoxygen, steam, air and carbon dioxide. All these injections successfullygenerated synthesis gas in the hot coke formation.

[2022] Low temperature pyrolysis experiments with tar sand wereconducted to determine a pyrolysis temperature zone and effects oftemperature in a heated portion on the quality of the producedpyrolyzation fluids. The tar sand was collected from the Athabasca tarsand region. FIG. 202 depicts a retort and collection system used toconduct the experiment.

[2023] Laboratory experiments were conducted on three tar samplescontained in their natural sand matrix. The three tar samples werecollected from the Athabasca tar sand region in western Canada. In eachcase, core material received from a well was mixed and then was split.One aliquot of the split core material was used in the retort, and thereplicate aliquot was saved for comparative analyses. Materials sampledincluded a tar sample within a sandstone matrix.

[2024] The heating rate for the runs was varied at 1° C./day, 5° C./day,and 10° C./day. The pressure condition was varied for the runs atpressures of 1 bar, 7.9 bars, and 28.6 bars. Run #78 was operated withno backpressure (about 1 bar absolute) and a heating rate of 1° C./day.Run #79 was operated with no backpressure (about 1 bar absolute) and aheating rate of 5° C./day. Run #81 was operated with no backpressure(about 1 bar absolute) and a heating rate of 10° C./day. Run #86 wasoperated at a pressure of 7.9 bars absolute and a heating rate of 10°C./day. Run #96 was operated at a pressure of 28.6 bars absolute and aheating rate of 10° C./day. In general, 0.5 to 1.5 kg initial weight ofthe sample was required to fill the available retort cells.

[2025] The internal temperature for the runs was raised from ambient to110° C., 200° C., 225° C. and 270° C., with 24 hours holding timebetween each temperature increase. Most of the moisture was removed fromthe samples during this heating. Beginning at 270° C., the temperaturewas increased by 1° C./day, 5° C./day, or 10° C./day until no furtherfluid was produced. The temperature was monitored and controlled duringthe heating of this stage.

[2026] Produced liquid was collected in graduated glass collectiontubes. Produced gas was collected in graduated glass collection bottles.Fluid volumes were read and recorded daily. Accuracy of the oil and gasvolume readings was within +/−0.6% and 2%, respectively. The experimentswere stopped when fluid production ceased. Power was turned off and morethan 12 hours was allowed for the retort to fall to room temperature.The pyrolyzed sample remains were unloaded, weighed, and stored insealed plastic cups. Fluid production and remaining rock material weresent out for analytical experimentation.

[2027] In addition, Dean Stark toluene solvent extraction was used toassay the amount of tar contained in the sample. In such an extractionprocedure, a solvent such as toluene or a toluene/xylene mixture ismixed with a sample and refluxed under a condenser using a receiver. Asthe refluxed sample condenses, two phases of the sample may separate asthey flow into the receiver. For example, tar may remain in the receiverwhile the solvent returns to the flask. Detailed procedures for DeanStark toluene solvent extraction are provided by the American Societyfor Testing and Materials. A 30 g sample from each depth was sent forDean Stark extraction analysis.

[2028] TABLE 26 illustrates the elemental analysis of initial tar and ofthe produced fluids for runs #81, #86, and #96. These data are all for aheating rate of 10° C./day. Only pressure was varied between the runs.TABLE 26 Run S # P (bar) C (wt %) H (wt %) N (wt %) O (wt %) (wt %)Initial — 82.43 10.20 0.45 1.74 5.18 Tar 81 1 84.61 12.35 0.06 0.51 2.4686 7.9 85.09 12.47 0.05 0.50 1.89 96 28.6 85.42 12.86 0.05 0.42 1.25 Run# P (bar) H/C N/C O/C S/C Initial Tar 1.475 0.0047 0.0158 0.0236 81 11.739 0.0006 0.0046 0.0109 86 7.9 1.746 0.0005 0.0044 0.0083 96 28.61.794 0.0005 0.0037 0.0055

[2029] As illustrated in TABLE 26, pyrolysis of the tar sand decreasesnitrogen, sulfur, and oxygen weight percentages in a produced fluid.Increasing the pressure in the pyrolysis experiment appears to decreasethe nitrogen, sulfur, and oxygen weight percentage in the producedfluids. In addition, the weight percentage of hydrogen and the hydrogento carbon ratio increase with increasing pressure.

[2030] TABLE 27 illustrates NOISE (Nitric Oxide Ionization SpectrometryEvaluation) analysis data for runs #81, #86, and #96 and the initialtar. NOISE has been developed as a quantitative analysis of the weightpercentages of the main constituents in oil. The remaining weightpercentage (47.2%) in the initial tar may be found in the high molecularweight residue. TABLE 27 P Paraffins Cycloalkanes Phenols Mono-aromaticsRun # (bar) (wt %) (wt %) (wt %) (wt %) Initial — 7.08 29.15 0 6.73 Tar81 1 15.36 46.7 0.34 21.04 86 7.9 27.16 45.8 0.54 16.88 96 28.6 26.4536.56 0.47 28.0 Di-aromatics Tri-aromatics Run # P (bar) (wt %) (wt %)Tetra-aromatics (wt %) Initial — 8.12 1.70 0.02 Tar 81 1 14.83 1.72 0.0186 7.9 9.09 0.53 0 96 28.6 8.52 0 0

[2031] As illustrated in TABLE 27, pyrolyzation of tar sand produces aproduct fluid with a significantly higher weight percentage ofparaffins, cycloalkanes, and mono-aromatics than found in the initialtar sand. Increasing the pressure up to 7.9 bars absolute appears tosubstantially eliminate the production of tetra-aromatics. Furtherincreasing the pressure up to 28.6 bars absolute appears tosubstantially eliminate the production of tri-aromatics. An increase inthe pressure also appears to decrease production of di-aromatics.Increasing the pressure up to 28.6 bars absolute also appears tosignificantly increase production of mono-aromatics. This may be due toan increased hydrogen partial pressure at the higher pressure. Theincreased hydrogen partial pressure may reduce the number ofpoly-aromatic compounds and increase the number of mono-aromatics,paraffins, and/or cycloalkanes.

[2032]FIG. 288 illustrates plots of weight percentages of carboncompounds versus carbon number for initial tar 2158 and runs atpressures of 1 bar absolute 2160, 7.9 bars absolute 2162, and 28.6 barsabsolute 2164 with a heating rate of 10° C./day. From the plots ofinitial tar 2158 and a pressure of 1 bar absolute 2160, it can be seenthat pyrolysis shifts an average carbon number distribution torelatively lower carbon numbers. For example, a mean carbon number inthe carbon distribution of plot 2158 is about carbon number nineteen anda mean carbon number in the carbon distribution of plot 2160 is aboutcarbon number seventeen. Increasing the pressure to 7.9 bars absolute2162 further shifts the average carbon number distribution to even lowercarbon numbers. Increasing the pressure to 7.9 bars absolute 2162 shiftsthe mean carbon number in the carbon distribution to a carbon number ofabout thirteen. Increasing the pressure to 28.6 bars absolute 2164reduces the mean carbon number to about eleven. Increasing the pressureis believed to decrease the average carbon number distribution byincreasing a hydrogen partial pressure in the product fluid. Theincreased hydrogen partial pressure in the product fluid allowshydrogenation, dearomatization, and/or pyrolysis of large molecules toform smaller molecules. Increasing the pressure also increases a qualityof the produced fluid. For example, the API gravity of the fluidincreased from about 6° for the initial tar, to about 31° for a pressureof 1 bar absolute, to about 39° for a pressure of 7.9 bars absolute, toabout 45° for a pressure of 28.6 bars absolute.

[2033]FIG. 289 illustrates bar graphs of weight percentages of carboncompounds for various pyrolysis heating rates and pressures. Bar 2166illustrates weight percentages for pyrolysis with a heating rate of 1°C./day at a pressure of 1 bar absolute. Bar 2168 illustrates weightpercentages for pyrolysis with a heating rate of 5° C./day at a pressureof 1 bar absolute. Bar 2170 illustrates weight percentages for pyrolysiswith a heating rate of 10° C./day at a pressure of 1 bar absolute. Bar2172 illustrates weight percentages for pyrolysis with a heating rate of10° C./day at a pressure of 7.9 bars absolute. Weight percentages ofparaffins 2174, cycloalkanes 2176, mono-aromatics 2178, di-aromatics2180, and tri-aromatics 2182 are illustrated in the bars. The barsdemonstrate that a variation in the heating rate between 1° C./day to10° C./day does not significantly affect the composition of the productfluid. Increasing the pressure from 1 bar absolute to 7.9 bars absolute,however, affects a composition of the product fluid. Such an effect maybe characteristic of the effects described in FIG. 288 and TABLES 26 and27 above.

[2034]FIG. 244 illustrates a drum experimental apparatus. This apparatuswas used to test Athabasca tar sands. Electric heater 1132 and beadheater 2022 were used to uniformly heat contents of drum 2024.Insulation 2004 surrounds drum 2024. Contents of drum 2024 were heatedat a rate of about 2° C./day at various pressures. Measurements fromtemperature gauges 2006 were used to determine an average temperature indrum 2024. Pressure in the drum was monitored with pressure gauge 1942.Product fluids were removed from drum 2024 through conduit 2008.Temperature of the product fluids was monitored with temperature gauge2006 on conduit 2008. A pressure of the product fluids was monitoredwith pressure gauge 1942 on conduit 2008. Product fluids were separatedin separator 2010. Separator 2010 separated product fluids intocondensable and non-condensable products. Pressure in separator 2010 wasmonitored with pressure gauge 1942. Non-condensable product fluids wereremoved through conduit 2012. A composition of a portion ofnon-condensable product fluids removed from separator 2010 wasdetermined by gas analyzer 2014. A portion of condensable product fluidswas removed from separator 2010. Compositions of the portion ofcondensable product fluids collected were determined by externalanalysis methods. Temperature of the non-condensable fluids wasmonitored with temperature gauge 2006 on conduit 2012. A pressure of thenon-condensable fluids was monitored with pressure gauge 1942 on conduit2012. Flow of non-condensable fluids from separator 2010 was determinedby flow meter 2018. Fluids measured in flow meter 2018 were collectedand neutralized in carbon bed 2020. Gas samples were collected in gascontainer 2026.

[2035] Drum 2024 was filled with Athabasca tar sand and heated. Allexperiments were conducted using the system shown in FIG. 244. Vaporswere produced from the drum, cooled, separated into liquids and gases,and then analyzed. Two separate experiments were conducted, each usingtar sand from the same batch, but the drum pressure was maintained at 1bar absolute in one experiment (the low pressure experiment), and thedrum pressure was maintained at 6.9 bars absolute in the otherexperiment (the high pressure experiment). The drum pressures wereallowed to autogenously increase to the maintained pressure astemperatures were increased. In the low pressure experiment, the acidnumber of the treated tar sands was found to be 0.02 mg/gram KOH.

[2036]FIG. 290 illustrates mole % of hydrogen in the gases during theexperiment (i.e., when the drum temperature was increased at the rate of2° C./day). Line 2184 illustrates results obtained when the drumpressure was maintained at 1 bar absolute. Line 2186 illustrates resultsobtained when the drum pressure was maintained at 6.9 bars absolute.FIG. 290 demonstrates that a higher mole percent of hydrogen wasproduced in the gas when the drum was maintained at lower pressures. Itis believed that increasing the drum pressure forced additional hydrogeninto the liquids in the drum. The hydrogen will tend to hydrogenateheavy hydrocarbons.

[2037]FIG. 291 illustrates API gravity of liquids produced from the drumas the temperature was increased in the drum. Plot 2188 depicts resultsfrom the high pressure experiment and plot 2190 depicts results from thelow pressure experiment. As illustrated in FIG. 291, higher qualityliquids were produced at the higher drum pressure. It is believed thathigher quality liquids were produced at the higher drum pressure becausemore hydrogenation occurred in the drum during the high pressureexperiment. Although the hydrogen concentration in the gas was lower inthe high pressure experiment, the drum pressures were significantlygreater. Therefore, the partial pressure of hydrogen in the drum wasgreater in the high pressure experiment.

[2038] Controlling a pressure and a temperature within a relativelypermeable formation will, in most instances, affect properties of theproduced formation fluids. For example, a composition or a quality offormation fluids produced from the formation may be altered by alteringan average pressure and/or an average temperature in the selectedsection of the heated portion. The quality of the produced fluids may bedefined by a property which may include, but is not limited to, APIgravity, percent olefins in the produced formation fluids, ethene toethane ratio, percent of hydrocarbons within produced formation fluidshaving carbon numbers greater than 25, total equivalent production (gasand liquid), and/or total liquids production. For example, controllingthe quality of the produced formation fluids may include controllingaverage pressure and average temperature in the selected section suchthat the average assessed pressure in the selected section may begreater than the pressure (p) as set forth in the form of EQN. 70 for anassessed average temperature (T) in the selected section:$\begin{matrix}{p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}} & (70)\end{matrix}$

[2039] where p is measured in psia (pounds per square inch absolute), Tis measured in Kelvin, and A and B are parameters dependent on the valueof the selected property.

[2040] EQN. 70 may be rewritten such that the natural log of pressuremay be a linear function of an inverse of temperature. This form of EQN.70 may be written as: In(p)=A/T+B. In a plot of the absolute pressure asa function of the reciprocal of the absolute temperature, A is the slopeand B is the intercept. The intercept B is defined to be the naturallogarithm of the pressure as the reciprocal of the temperatureapproaches zero. Therefore, the slope and intercept values (A and B) ofthe pressure-temperature relationship may be determined from twopressure-temperature data points for a given value of a selectedproperty. The pressure-temperature data points may include an averagepressure within a formation and an average temperature within theformation at which the particular value of the property was, or may be,produced from the formation. For example, the pressure-temperature datapoints may be obtained from an experiment such as a laboratoryexperiment or a field experiment.

[2041] A relationship between the slope parameter, A, and a value of aproperty of formation fluids may be determined. For example, values of Amay be plotted as a function of values of a formation fluid property. Acubic polynomial may be fitted to these data. For example, a cubicpolynomial relationship such as EQN. 71

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (71)

[2042] may be fitted to the data, where a₁, a₂, a₃, and a₄ are empiricalconstants that describe a relationship between the first parameter, A,and a property of a formation fluid. Alternatively, relationships havingother functional forms such as another order polynomial or a logarithmicfunction may be fitted to the data. Values of a₁, a₂, . . . , may beestimated from the results of the data fitting. Similarly, arelationship between the second parameter, B, and a value of a propertyof formation fluids may be determined. For example, values of B may beplotted as a function of values of a property of a formation fluid. Acubic polynomial may also be fitted to the data. For example, a cubicpolynomial relationship such as EQN. 72

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄  (72)

[2043] may be fitted to the data, where b₁, b₂, b₃, and b₄ are empiricalconstants that describe a relationship between the parameter B and thevalue of a property of a formation fluid. As such, b₁, b₂, b₃, and b₄may be estimated from results of fitting the data. TABLES 28 and 29 listestimated empirical constants determined for several properties of thetar (or hydrocarbons) for production from Athabasca tar sands. TABLE 28PROPERTY a₁ a₂ a₃ a₄ API Gravity (°) 1.241538 −63.488 399.8138 −2563.58Ethene/Ethane 703115.4 595728.3 −113788 −6696.36 Ratio Weight Percent of−9.98205639 280.8493405 −2882.17 −13199.4 Hydrocarbons Having a CarbonNumber Greater Than 25 Equivalent Liquid −139.727 11019.07 −2874162438177.26 Production (gal/ton)

[2044] TABLE 29 PROPERTY b₁ b₂ b₃ b₄ API Gravity (°) −.00969 0.913396−28.7662 328.0794 Ethene/Ethane −1502.05 −759.361 131.31749 16.12737Ratio Weight Percent 0.01393835 −0.395164411 4.092876 25.23222 of Hydro-carbons Having a Carbon Number Greater Than 25 Equivalent 0.010799−2.50854 192.3489 −4804.5858 Liquid Pro- duction (gal/ton)

[2045] To determine an average pressure and an average temperature toproduce a formation fluid having a selected property, the value of theselected property and the empirical constants as described above may beused to determine values for the first parameter A and the secondparameter B according to EQNS. 73 and 74:

A=a ₁*(property)³ +a ₂*(property)²+a₃*(property)+a₄  (73)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b₄.  (74)

[2046] Experimental data from the experiment described above for FIG.202 were used to determine a pressure-temperature relationship relatingto the quality of the produced fluids. Varying the operating conditionsincluded altering temperatures and pressures. Various samples of tarsands were pyrolyzed at various operating conditions. The quality of theproduced fluids was described by a number of desired properties. Desiredproperties included API gravity, an ethene to ethane ratio, equivalentliquids produced (gas and liquid), and percent of fluids with carbonnumbers greater than about 25. Based on data collected from theseequilibrium experiments, families of curves for several values of eachof the properties were constructed as shown in FIGS. 292-295. From thesefigures, EQNS. 75, 76, and 77 were used to describe the functionalrelationship of a given value of a property:

P=exp[(A/T)+B],  (75)

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄  (76)

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄.  (77)

[2047] The generated curves may be used to determine a preferredtemperature and a preferred pressure that produce fluids with desiredproperties. Data illustrating the pressure-temperature relationship of anumber of the desired properties for tar sands samples was plotted in anumber of the following figures.

[2048] In FIG. 292, a plot of gauge pressure versus temperature isdepicted. Lines representing the fraction of products with carbonnumbers greater than about 25 were plotted. For example, when operatingat a temperature of 375° C. and a pressure of 3.8 bars absolute, about5% of the produced fluid hydrocarbons had a carbon number equal to orgreater than 25. At low pyrolysis temperatures and high pressures, thefraction of produced fluids with carbon numbers greater than about 25decreases. Therefore, operating at a high pressure and a pyrolysistemperature at the lower end of the pyrolysis temperature zone tends todecrease the fraction of fluids with carbon numbers greater than 25produced from tar sands.

[2049]FIG. 293 illustrates oil quality produced from tar sands as afunction of pressure and temperature. Lines indicating different oilqualities, as defined by API gravity, are plotted. For example, thequality of the produced oil was about 35° API when pressure wasmaintained at about 5.5 bars absolute and a temperature was about 375°C. Low pyrolysis temperatures and relatively high pressures may producea high API gravity oil.

[2050]FIG. 294 illustrates an ethene to ethane ratio produced from tarsands as a function of pressure and temperature. For example, at apressure of 14.8 bars absolute and a temperature of 375° C., the ratioof ethene to ethane is approximately 0.01. The volume ratio of ethene toethane may predict an olefin to alkane ratio of hydrocarbons producedduring pyrolysis. To control olefin content, operating at lowerpyrolysis temperatures and a higher pressure may be beneficial. Olefincontent may be reduced by operating at a low pyrolysis temperature and ahigh pressure.

[2051]FIG. 295 depicts the yield of equivalent liquids produced from tarsands as a function of temperature and pressure. Line 2192 representsthe pressure-temperature combination at which 8.38×10⁻⁵ m³ of fluid perkilogram of tar sands (20 gallons/ton) is produced. Thepressure/temperature plot results in line 2194 for the production oftotal fluids per ton of tar sands equal to 1.05×10⁻⁵ m³/kg (25gallons/ton). For example, at a temperature of about 325° C. and apressure of about 4.5 bars absolute, the resulting equivalent liquidsproduced was about 8.38×10⁻⁵ m³/kg. As the temperature of the retortincreased and the pressure decreased, the yield of the equivalentliquids produced increased. Equivalent liquids produced is defined asthe amount of liquids equivalent to the energy value of the produced gasand liquids.

[2052] A three-dimensional (3-D) simulation model (STARS, ComputerModeling Group (CMG), Calgary, Canada) was used to simulate an in situconversion process for a tar sands formation. A heat injection rate wascalculated using a separate numerical code (CFX, AEA Technology,Oxfordshire, UK). The initial heat injection rate was calculated at 500watts per foot (1640 watts per meter). The 3-D simulation was based on adilation-recompaction model for tar sands. A target zone thickness of 50m was used. Input data for the simulation were based on averagereservoir properties of the Grosmont formation in northern Alberta,Canada as follows:

[2053] Depth of target zone=280 m;

[2054] Thickness=50 m;

[2055] Porosity=0.27;

[2056] Oil saturation=0.84;

[2057] Water saturation=0.16;

[2058] Permeability=1000 millidarcy;

[2059] Vertical permeability versus horizontal permeability=0.1;

[2060] Overburden=shale; and

[2061] Base rock=wet carbonate.

[2062] Six component fluids were used in the STARS simulation based onfluids found in Athabasca tar sands. The six component fluids were:heavy fluid, light fluid, gas, water, pre-char, and char. The spacingbetween heater wells was set at 9.1 m on a triangular pattern. In onesimulation, eleven horizontal heaters, each with a 91.4 m heater lengthwere used with initial heat outputs set at the previously calculatedvalue of 1640 watts per meter. A vertical production well was placed ata center of the formation.

[2063]FIG. 296 illustrates a plot of percentage oil recovery (percentageof initial volume of oil in place recovered) versus temperature (indegrees Celsius) for a laboratory experiment (data from the pyrolysisexperiments of FIG. 202) and a simulation. The pressure in thelaboratory experiment and in a production well in the simulation wasatmospheric pressure (about 1 bar absolute bottomhole pressure). As canbe seen from the plots, simulation recovery data 2196 was in relativelygood agreement with the experimental recovery data 2198. FIG. 297depicts temperature (in degrees Celsius) versus time (in days) for thelaboratory experiment and the simulation. As is the case with oilrecovery, simulation data 2200 was in relatively good agreement withexperimental data 2202.

[2064]FIG. 298 illustrates a plot of cumulative oil production (in cubicmeters) versus time (in days) for various bottomhole pressures at aproducer well. Plot 2204 illustrates oil production for a pressure of1.03 bars absolute. Plot 2206 illustrates oil production for a pressureof 6.9 bars absolute. FIG. 298 demonstrates that an increase inbottomhole pressure decreases oil production in a tar sands formation.Simulation data illustrated in FIGS. 299, 300, and 301-306 weredetermined for a bottomhole pressure of about 1 bar absolute.

[2065]FIG. 299 illustrates a plot of a ratio of energy content ofproduced fluids from a reservoir against energy input to heat thereservoir versus time (in days). Plot 2208 illustrates the ratio versustime for heating an entire reservoir to a pyrolysis temperature. Plot2210 illustrates the ratio versus time for allowing partial drainage inthe reservoir into a selected pyrolyzation section. FIG. 299demonstrates that allowing partial drainage in the reservoir tends toincrease the energy content of produced fluids versus heating the entirereservoir, for a given energy input into the reservoir.

[2066]FIG. 300 illustrates a plot of weight percentage versus carbonnumber distribution obtained from laboratory experiments and used in thesimulation. Plot 2212 illustrates the carbon number distribution for theinitial tar sand. The initial tar sand has an API gravity of 6°. Plot2214 illustrates the carbon number distribution for in situ conversionof the tar sand up to a temperature of 350° C. Plot 2214 has an APIgravity of 30°. From FIG. 300, it can be seen that the in situconversion process increases the quality of oil found in the tar sands,as evidenced by the increased API gravity and the carbon numberdistribution shift to lower carbon numbers. The lower carbon numberdistribution was evidence that a large portion of the produced fluid wasproduced as a vapor.

[2067]FIG. 301 illustrates percentage cumulative oil recovery versustime (in days) for the simulation using horizontal heaters. As seen fromplot 2216, a total mass recovery approached about 70% at about 1800days. This is comparable to results obtained from the pyrolysisexperiments of FIG. 202 (as shown in FIG. 296). FIG. 302 illustrates oilproduction rates (m³/day) versus time (in days) for heavy hydrocarbons2218 and light hydrocarbons 2220. Heavy hydrocarbon production 2218reached a maximum of about 3 m³/day at about 150 days. Light hydrocarbonproduction 2220 reached a maximum of about 9.6 m³/day at about 950 days.In addition, almost all heavy hydrocarbon production 2218 was completebefore the onset of light hydrocarbon production 2220. The early heavyhydrocarbon production was attributed to production of cold (relativelyunheated and unpyrolyzed) heavy hydrocarbons.

[2068] It should be noted that oil production rates (m³/day), cumulativeoil production data (m³), and other non-averaged number valuesdetermined using the simulations as described herein are calculated forsymmetry elements within the simulation. Thus, absolute values of oilproduction rates, cumulative oil production data, and other non-averagednumber values between simulations with different symmetry elements willdiffer based on the size or scope of the symmetry elements.

[2069] In some embodiments, early production of heavy hydrocarbons maybe undesirable. FIG. 303 illustrates oil production rates (m³/day)versus time (days) for heavy hydrocarbons 2218 and light hydrocarbons2220 with production inhibited for the first 500 days of heating. Heavyhydrocarbon production 2218 in FIG. 303 was significantly lower thanheavy hydrocarbon production 2218 in FIG. 302. Light hydrocarbonproduction 2220 in FIG. 303 was higher than light hydrocarbon production2220 in FIG. 302, reaching a maximum of about 11.5 m³/day at about 950days. The percentage of light hydrocarbons to heavy hydrocarbons wasincreased by inhibiting production the first 500 days of heating.

[2070] Inhibiting production during heating can significantly increasethe pressure in the formation. FIG. 304 depicts average pressure in theformation (bars absolute) versus time (days). Plot 2222 depicts theaverage pressure for inhibited production during the first 500 days ofheating. The average pressure reached a maximum of about 320 barsabsolute at 500 days. Plot 2224 depicts the average pressure forinhibited production until 500 days with four additional verticalproducer wells placed proximate the heater wells. Production through thefour additional vertical producer wells was limited such that smallamounts of hydrocarbons were produced to relieve pressure in theformation. In this case, the average pressure decreased to about 185bars absolute at 500 days. Thus, producing small amounts of hydrocarbonsduring early stages of production can be effective for controllingpressure within the formation.

[2071]FIG. 305 illustrates cumulative oil production (m³) versus time(days) for vertical producer 2226 and horizontal producer 2228 for thesimulation using horizontal heater wells. As shown in FIG. 305, therewas relatively little difference in cumulative oil production betweenusing a horizontal producer in the middle of the formation or a verticalproducer in the simulation. Vertical or slanted wells may be easierand/or cheaper to install than horizontal wells. Using vertical orslanted production wells may improve an economic outlook for a proposedin situ system.

[2072]FIG. 306 illustrates percentage cumulative oil recovery versustime (days) for three different horizontal producer well locations: top2230, middle 2232, and bottom 2234. The highest cumulative oil recoverywas obtained using bottom producer 2234. There was relatively littledifference in cumulative oil recovery between middle producer 2232 andtop producer 2230. FIG. 307 illustrates production rates (m³/day) versustime (days) for heavy hydrocarbons and light hydrocarbons for the middleand bottom producer locations. As seen in FIG. 307, heavy hydrocarbonproduction with bottom producer 2236 was more than heavy hydrocarbonproduction with middle producer 2238. There was relatively littledifference between light hydrocarbon production with bottom producer2240 and light hydrocarbon production with middle producer 2242. Highercumulative oil recovery obtained with the bottom producer (shown in FIG.306) may be due to increased heavy hydrocarbon production.

[2073] A second tar sands simulation for the Grosmont reservoir used sixvertical heater wells and a vertical producer well in a seven spotpattern with a spacing of 9.1 m between wells. The bottomhole pressurein the vertical producer well was about 1 bar absolute. FIG. 308illustrates percentage cumulative oil recovery versus time (in days) forthe second Grosmont tar sands simulation. Plot 2244 shows a total massrecovery approached about 70% after 1800 days, which is comparable toresults of the pyrolysis experiments of FIG. 202 (as shown in FIG. 296).

[2074]FIG. 309 illustrates oil production rates (m³/day) versus time (indays) for heavy hydrocarbons 2218 and light hydrocarbons 2220 for thesecond Grosmont tar sands simulation. FIG. 309 shows that heavyhydrocarbon production 2218 reached a maximum of about 0.08 m³/day atabout 700 days. Light hydrocarbon production 2220 reached a maximum ofabout 0.22 m³/day at about 800 days. The heavy hydrocarbon production(shown in FIG. 309) takes place at a later time than heavy hydrocarbonproduction for horizontal heater wells (shown in FIG. 302).

[2075] Simulations were performed using the 3-D simulation model (STARS)to simulate an in situ conversion process for a tar sands formation. Aseparate numerical code using finite difference simulation (CFX) wasused to calculate heat input data for the formations and well patterns.The heat input data was used as boundary conditions in the 3-Dsimulation model.

[2076]FIG. 310 illustrates a pattern of heater/producer wells used toheat a tar sands formation in the simulation. In the simulation, sixheater/producer wells 2246 were placed in formation 2248. FIG. 311illustrates a pattern of heater/producer wells used in the simulationwith three heater/producer wells 2246, one cold producer well 2250, andthree heater wells 520. Cold producer well 2250 has no heating elementplaced within the well. FIG. 312 illustrates a pattern of six heaterwells 520 and one cold producer well 2250 used in the simulation. Thepattern of wells used in each simulation is similar to that for theembodiment described in reference to FIG. 141. Heater wells had ahorizontal length (i.e., length perpendicular to the pattern in thedrawings) of 91.4 m in the simulations.

[2077] Parameters for the simulations are based on formation propertiesof the Peace River basin in Alberta, Canada:

[2078] Formation thickness=28 m, in which the formation has three layers(estuarine, lower estuarine, and fluvial);

[2079] Estuarine thickness=10 m (upper portion of formation);

[2080] porosity=0.28;

[2081] permeability=150 millidarcy;

[2082] vertical permeability/horizontal permeability=0.07;

[2083] oil saturation=0.79;

[2084] Lower estuarine thickness=9 m (middle portion of formation);

[2085] porosity=0.28;

[2086] permeability=825 millidarcy;

[2087] vertical permeability/horizontal permeability=0.6;

[2088] oil saturation=0.81;

[2089] Fluvial thickness=9 m (lower portion of formation);

[2090] porosity=0.30;

[2091] permeability=1500 millidarcy;

[2092] vertical permeability/horizontal permeability=0.7;

[2093] oil saturation=0.81.

[2094] Simulation data illustrated in FIGS. 313-322 were determined fora bottomhole pressure of about 1 bar absolute. FIG. 313 illustratescumulative oil production (m³) versus time (days) for the simulation ofFIG. 310. Plot 2252 illustrates cumulative heavy hydrocarbon productionversus time. Plot 2254 illustrates cumulative light hydrocarbonproduction versus time. As shown in FIG. 313, light hydrocarbonproduction exceeds heavy hydrocarbon production for the case of sixheater/producer wells. Light hydrocarbon production at about 2000 dayswas about 3650 m³, while heavy hydrocarbon production at the same timewas about 2700 m³.

[2095]FIG. 314 illustrates cumulative oil production (m³) versus time(days) for the simulation of FIG. 311. Plot 2256 illustrates cumulativeheavy hydrocarbon production versus time. Plot 2258 illustratescumulative light hydrocarbon production versus time. As shown in FIG.314, light hydrocarbon production exceeds heavy hydrocarbon for thesimulation. Light hydrocarbon production at about 2000 days was about4930 m³, while heavy hydrocarbon production at the same time was about650 m³. In this case, light hydrocarbon production was greater thanheavy hydrocarbon production. A ratio of light hydrocarbon production toheavy hydrocarbon production for this simulation was greater than aratio of light hydrocarbon production to heavy hydrocarbon productionfor the simulation in FIG. 310 (as shown in FIG. 313).

[2096]FIG. 315 illustrates cumulative oil production (m³) versus time(days) for the simulation of FIG. 312. Plot 2260 illustrates cumulativeheavy hydrocarbon production versus time. Plot 2262 illustratescumulative light hydrocarbon production versus time. As shown in FIG.315, heavy hydrocarbon production exceeds that of light hydrocarbonproduction using a cold producer well at the bottom of the formation.Light hydrocarbon production was about 3000 m³ at about 2000 days, whileheavy hydrocarbon production at the same time was about 4100 m³. Lighthydrocarbon production was lower than the previous simulations, whileheavy hydrocarbon production (and total oil production) increased.

[2097]FIG. 316 illustrates cumulative gas production (m³) and cumulativewater production (m³) versus time (days) for the simulation of FIG. 310.Plot 2264 illustrates cumulative water production versus time. Plot 2266illustrates cumulative gas production versus time. FIG. 317 illustratescumulative gas production (m³) and cumulative water production (m³)versus time (days) for the simulation of FIG. 311. Plot 2268 illustratescumulative water production versus time. Plot 2270 illustratescumulative gas production versus time. FIG. 318 illustrates cumulativegas production (m³) and cumulative water production (m³) versus time(days) for the simulation of FIG. 312. Plot 2272 illustrates cumulativewater production versus time. Plot 2274 illustrates cumulative gasproduction versus time. As shown in FIGS. 316, 317, and 318, waterproduction was relatively constant in the three simulations (about 2700m³ barrels after about 2000 days). Gas production was the highest inFIG. 317, with about 4.8×10⁵ m³ after about 2000 days. Gas productionwas the lowest in FIG. 318, at about 3.7×10⁵ m³ at about 3000 days.

[2098]FIG. 319 illustrates an energy ratio versus time for thesimulation of FIG. 310. Plot 2276 illustrates the energy ratio (energyproduced divided by energy injected) versus time (days). FIG. 320illustrates an energy ratio versus time for the simulation of FIG. 311.Plot 2278 illustrates the energy ratio versus time (days). FIG. 321illustrates an energy ratio versus time for the simulation of FIG. 312.Plot 2280 illustrates the energy ratio versus time (days). As shown inFIGS. 319 and 320, the energy ratio in these simulations are relativelysimilar. FIG. 321 shows a greater energy ratio due to the high energycontent of the heavy hydrocarbons produced in the bottom cold producer.However, the heavy hydrocarbons produced in the bottom cold producerwere of lower quality than oil produced with six heater/producer wellsand/or production through an upper portion of the formation.

[2099]FIG. 322 illustrates an average API gravity of produced fluidversus time (days) for the simulations in FIGS. 310-312. Plot 2282illustrates the average API gravity versus time for the simulation ofFIG. 310 using six heater/producer wells. Plot 2284 illustrates theaverage API gravity versus time for the simulation of FIG. 311 usingthree heater/producer wells and a cold production well. Plot 2286illustrates the average API gravity versus time for the simulation ofFIG. 312 using six heater wells and a bottom cold producer. As shown inFIG. 322, higher quality oil (higher average API gravity) was producedfor the simulation of FIG. 311. This may be attributed to moresignificant upgrading of the oil proximate the heater/producer wells andcold producer in the upper portion of the formation. Oil produced in thesimulation of FIG. 311 appears to have a larger vapor phase componentthan oil produced in the simulations of FIGS. 310 and 312.

[2100]FIG. 323 depicts a heater well pattern used in the 3-D STARSsimulation. Heater wells 520 were placed in a pattern similar to theheater wells of FIGS. 310-312. A horizontal spacing between heater wellswas about 15 m, as shown in FIG. 323, and the heater wells had ahorizontal length of 91.4 m. A location of the production well wasvaried between middle producer location 2288 and bottom producerlocation 2290 for the data shown in FIGS. 324, 325, and 326-329.

[2101]FIG. 324 illustrates an energy out/energy in ratio versus time(days) for production through a middle producer location with abottomhole pressure of about 1 bar absolute. The reservoir was treatedby heating the full reservoir uniformly (plot 2292) and by stagedheating of the reservoir (plot 2294). Staged heating of the reservoirincluded turning off the top heaters at 690 days, the middle upperheater at 810 days, and the middle lower heater and bottom heaters at1320 days. As shown in FIG. 324, staged heating (plot 2294) of thereservoir produced a higher energy out/energy in ratio than fullreservoir heating (plot 2292). The amount of energy input into theformation is lower with the staged heating process, which may contributeto the higher energy out/energy in ratio.

[2102]FIG. 325 illustrates percentage cumulative oil recovery versustime (days) for production using a middle producer location and a bottomproducer location with a bottomhole pressure of about 1 bar absolute.Plot 2296 illustrates production using middle producer location. Plot2298 illustrates production using bottom producer location. As shown inFIG. 325, producing through the production well located at the bottom ofthe formation resulted in higher total oil recovery from the formation.However, most of the increased total oil recovery was due to productionof heavy hydrocarbons rather than light hydrocarbons from the formation.Economic considerations may determine a desired ratio of heavyhydrocarbons to light hydrocarbons and locations of production wells toproduce the desired ratio.

[2103]FIG. 330 illustrates cumulative oil produced (cm³/kg) versustemperature (degrees Celsius) for lab pyrolysis experiments 2300 (asdetermined with the experimental apparatus of FIG. 202) and forsimulation 2302 with a bottomhole pressure of about 7.9 bars absolute.As shown in FIG. 330, cumulative oil production versus temperature forthe simulation was in good agreement with pyrolysis experimental data.

[2104]FIG. 326 illustrates cumulative oil production (m³) versus time(days) using a middle producer location and a bottomhole pressure ofabout 7.9 bars absolute. Cumulative heavy hydrocarbon production 2304was about 600 m³ after about 800 days. Cumulative light hydrocarbonproduction 2306 was about 3975 m³ after about 1500 days. Totalcumulative production 2308 was about 4575 m³ after complete lighthydrocarbon production.

[2105]FIG. 327 illustrates API gravity of oil produced and oilproduction rates (m³/day) for heavy hydrocarbons and light hydrocarbonsfor a middle producer location and a bottomhole pressure of about 7.9bars absolute. As shown in FIG. 327, light hydrocarbon production 2310takes place at a later time than heavy hydrocarbon production 2312. APIgravity 2314 of the combined production increased to a maximum of about40° at the same time the light hydrocarbon production rate 2310maximized (about 900 days) and when heavy hydrocarbon production 2312was substantially complete.

[2106]FIG. 328 illustrates cumulative oil production (m³) versus time(days) for a bottom producer location and a bottomhole pressure of about7.9 bars absolute. Cumulative heavy hydrocarbon production 2304 wasabout 3370 m³ after about 1000 days. Cumulative light hydrocarbonproduction 2306 was about 2080 m³ after about 1100 days. Totalcumulative production 2308 was about 5450 m³ after complete lighthydrocarbon production. The earlier production time for the bottomproducer location compared to production with the middle producerlocation (as shown in FIGS. 326 and 327) may be due to an increasedproduction of cold (unpyrolyzed) hydrocarbons at the bottom producerlocation caused by gravity drainage of the fluids. The increasedproduction of heavy (cold) hydrocarbons increased the total cumulativeoil production (total mass recovery) from the formation.

[2107]FIG. 329 illustrates API gravity of oil produced and oilproduction rates (m³/day) for heavy hydrocarbons and light hydrocarbonsfor a bottom producer location and a bottomhole pressure of about 7.9bars absolute. As shown in FIG. 329, light hydrocarbon production 2310takes place at a later time than heavy hydrocarbon production 2312, asshown in FIG. 327 for a middle producer location. API gravity 2314 ofthe combined production increased to a maximum of about 35° at about1200 days, which is about the same time heavy hydrocarbon production wascomplete. The lower API gravity shown in FIG. 329 compared to the APIgravity obtained using the middle producer location (shown in FIG. 327)was probably due to increased production of heavy (cold) hydrocarbonsduring the early stages of production.

[2108]FIG. 331 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 2316 and light hydrocarbons 2318 producedthrough a middle producer location and a bottomhole pressure of about7.9 bars absolute. The heater well pattern for the simulation wasidentical to the heater well pattern in FIG. 323 with the horizontalheater spacing increased from 15 m to 18.3 m. As shown in FIG. 331,production rates of light hydrocarbons and heavy hydrocarbons for thewider spacing (18.3 m) was relatively similar to production rates forthe narrower spacing (15 m), as shown in FIG. 327. Production startedlater in FIG. 331, however, which may be attributed to a slower heatingrate caused by the wider spacing.

[2109]FIG. 332 illustrates cumulative oil production (m³) versus time(days) for the wider horizontal heater spacing of 18.3 m with productionthrough a middle producer location and a bottomhole pressure of about7.9 bars absolute. Cumulative heavy hydrocarbon production 2304 wasabout 265 m³ after about 800 days. Cumulative light hydrocarbonproduction 2306 was about 5432 m³ after about 2000 days. A totalcumulative production 2308 was about 5700 m³ after completed lighthydrocarbon production. Although the wider heater spacing increased theproduction time (as shown in FIG. 331), the total recovery of oil wasgreater for the wider heater spacing than for the narrower heaterspacing. In addition, the wider heater spacing appeared to increase thepercentage of light hydrocarbons in the total oil recovered (i.e., thelight hydrocarbon versus heavy hydrocarbon ratio) compared to thenarrower spacing (as shown in FIG. 326).

[2110]FIG. 333 depicts another heater well pattern used in the 3-D STARSsimulation. Heater wells 520 were placed in a triangular pattern. Heaterwells had a horizontal length of 91.4 m in the triangular pattern. Coldproduction well 2250 was located near the middle of the formation. FIG.334 illustrates oil production rates (m³/day) versus time (days) forheavy hydrocarbons 2316 and light hydrocarbons 2318 produced throughcold production well 2250 located in the middle of the formation in FIG.333 and a bottomhole pressure of about 7.9 bars absolute. As shown inFIG. 334, production rates of light hydrocarbons and heavy hydrocarbonsfor the triangular pattern were relatively similar to production ratesfor the hexagonal pattern of FIG. 323 (as shown in FIG. 327). The lighthydrocarbon production rate in FIG. 334 for the triangular pattern wassomewhat lower than the light hydrocarbon production rate in FIG. 327for the hexagonal pattern. The lower production rate for the triangularpattern was probably caused by the increased spacing between heaters inthe triangular pattern. The increased spacing appeared to cause a largerreduction in the heavy hydrocarbon production rate than in the lighthydrocarbon production rate.

[2111]FIG. 335 illustrates cumulative oil production (m³) versus time(days) for the triangular heater pattern shown in FIG. 333 and abottomhole pressure of about 7.9 bars absolute. Cumulative heavyhydrocarbon production 2304 was about 90 m³ after about 500 days.Cumulative light hydrocarbon production 2306 was about 3020 m³ afterabout 1500 days. A total cumulative production 2308 was about 3100 m³after complete light hydrocarbon production. The triangular heaterspacing appeared to decrease the production rate (as shown in FIG. 334)and the total cumulative production (as shown in FIG. 335). Thetriangular heater spacing increased the percentage of light hydrocarbonsin the total oil recovered (i.e., the light hydrocarbon versus heavyhydrocarbon ratio) relative to the wider heater spacing (as shown inFIG. 332) and the narrower heater spacing (as shown in FIG. 326).

[2112]FIG. 336 illustrates a heater well and producer well pattern usedfor a 3-D STARS simulation. Heater wells 520A-520L were placedhorizontally in formation 678 in an alternating triangular pattern asshown in FIG. 336. Heater wells had a horizontal length of 91.4 m in thealternating triangular pattern. A horizontal producer well was placedproximate a top of the formation (top production well 2320), in a middleof the formation (middle production well 2322), or proximate a bottom ofthe formation (bottom production well 2324).

[2113]FIG. 337 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 2316 and light hydrocarbons 2318 forproduction using bottom production well and a bottomhole pressure ofabout 7.9 bars absolute. As shown in FIG. 337, heavy hydrocarbonproduction 2316 was significant during early stages of production(before about 250 days). After about 200 days, oil production appearedto shift to light hydrocarbon production 2318. Plot 2326 illustratesaverage pressure in the formation versus time. The average pressure inthe formation appeared to rise during the early stages of heavyhydrocarbon production. As light hydrocarbon production began, theaverage pressure began to decrease.

[2114]FIG. 338 illustrates cumulative oil production (m³) versus time(days) for production through a bottom production well and a bottomholepressure of about 7.9 bars absolute. Plot 2328 depicts cumulative heavyhydrocarbon production. Plot 2330 depicts cumulative light hydrocarbonproduction. Plot 2332 depicts total (heavy and light) cumulativeoil-production. As shown in FIG. 338, heavy hydrocarbon production (plot2328) was about 1600 m³ after about 240 days. Light hydrocarbonproduction was about 2900 m³ after about 450 days. Total cumulative oilproduction was about 4500 m³. As shown in FIGS. 337 and 338, heavyhydrocarbon production was significant, which is likely caused bygravity drainage of fluids towards the bottom production well. Aftertemperatures in the formation reached pyrolysis temperatures, thecracking of heavy hydrocarbons to form light hydrocarbons in theformation increased and production shifted to light hydrocarbonproduction.

[2115]FIG. 339 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbons 2316 and light hydrocarbons 2318 forproduction using a middle production well and a bottomhole pressure ofabout 7.9 bars absolute. As shown in FIG. 339, some heavy hydrocarbonproduction occurred before light hydrocarbon production began. There is,however, less heavy hydrocarbon production than for the simulation usinga bottom production well (shown in FIG. 337). A maximum production rateof heavy hydrocarbons in FIG. 339 was about 9 m³/day while a maximumproduction rate of heavy hydrocarbons in FIG. 337 was about 23 m³/day.Plot 2334 illustrates average pressure in the formation versus time. Theaverage pressure in the formation appeared to rise slightly during theearly stages of heavy hydrocarbon production and decrease slightly withthe onset of light hydrocarbon production.

[2116]FIG. 340 illustrates cumulative oil production (m³) versus time(days) for production through a middle production well and a bottomholepressure of about 7.9 bars absolute. Plot 2336 depicts cumulative heavyhydrocarbon production. Plot 2338 depicts cumulative light hydrocarbonproduction. Plot 2340 depicts total (heavy and light) cumulative oilproduction. As shown in FIG. 340, heavy hydrocarbon production (plot2336) was about 790 m³ after about 225 days. Light hydrocarbonproduction was about 3200 m³ after about 520 days. Total cumulative oilproduction was about 4190 m³. There was slightly less total cumulativeoil production for a middle production well than for a bottom productionwell. The decreased cumulative oil production in the middle productionwell is likely caused by increased heavy hydrocarbon production throughthe bottom production well. As shown in FIGS. 337-340, light hydrocarbonproduction was higher and heavy hydrocarbon production was lower for themiddle production well than for the bottom production well.

[2117]FIG. 341 illustrates oil production rates (m³/day) versus time(days) for heavy hydrocarbon production 2316 and light hydrocarbonproduction 2318 for production using a top production well and abottomhole pressure of about 7.9 bars absolute. As shown in FIG. 341,light hydrocarbon production for the top production well was somewhathigher than light hydrocarbon production from the middle production well(as shown in FIG. 339). Heavy hydrocarbon production for the topproduction well was less than heavy hydrocarbon production for thebottom production well (as shown in FIG. 337). The production of heavyhydrocarbons decreased as the production well was placed closer to thetop of the formation. The decreased production of heavy hydrocarbons maybe caused by gravity drainage of the heavy hydrocarbons as the heavyhydrocarbons are mobilized as well as an increase in production offluids in the vapor phase at the top of the formation. Plot 2342illustrates average pressure in the formation versus time. The averagepressure in the formation appeared to rise significantly until the onsetof light hydrocarbon production.

[2118]FIG. 342 illustrates cumulative oil production (m³) versus time(days) for production through a top production well and a bottomholepressure of about 7.9 bars absolute. Plot 2344 depicts cumulative heavyhydrocarbon production. Plot 2346 depicts cumulative light hydrocarbonproduction. Plot 2348 depicts total (heavy and light) cumulative oilproduction. As shown in FIG. 342, heavy hydrocarbon production (plot2344) was about 790 m³ after about 225 days. Light hydrocarbonproduction was about 3200 m³ after about 520 days. Total cumulative oilproduction was about 4190 m³. Cumulative oil production through the topproduction well was substantially similar to cumulative oil productionthrough the middle production well. As shown in FIGS. 339-342, heavyhydrocarbon production occurred earlier for production through themiddle production well than for production through the top productionwell. In FIG. 340, for example, cumulative heavy hydrocarbon production2336 was about 590 m³ at 200 days. In FIG. 342, cumulative heavyhydrocarbon production (plot 2344) was about 320 m³ at 200 days. Asshown in FIG. 341, for production through the top production well, heavyhydrocarbon production 2318 increased when light hydrocarbon production2316 began. The increased heavy hydrocarbon production may be caused byvapor phase transport of heavy hydrocarbons towards the top productionwell.

[2119]FIG. 343 illustrates oil production rates (m³/day) versus time forheavy hydrocarbons 2316 and light hydrocarbons 2318 for producing fluidsthrough heater wells 520A-520L as shown in FIG. 336 and a bottomholepressure of about 7.9 bars absolute. As shown in FIG. 343, overall heavyhydrocarbon production and most heavy hydrocarbon production weresignificantly reduced prior to light hydrocarbon production. Heating ofthe production wells within the formation most likely increased lighthydrocarbon production. Cracking of hydrocarbons at a heated productionwell tends to increase vapor phase production at the heated productionwell.

[2120]FIG. 344 depicts another well pattern used in a simulation. Thewell pattern in FIG. 344 includes the heater pattern of FIG. 336 withthree production wells 512 placed in an upper portion of the formation.Heater wells had a horizontal length of 91.4 m in the simulation. FIG.345 illustrates oil production rates (m³/day) versus time (days) forheavy hydrocarbons 2316 and light hydrocarbons 2318 for production wells512 in FIG. 344 and a bottomhole pressure of about 7.9 bars absolute. Asshown in FIG. 345, light hydrocarbon and heavy hydrocarbon productionprior to 200 days was slightly higher than light hydrocarbon and heavyhydrocarbon production with top production well (as shown in FIG. 341).The early production of light and heavy hydrocarbons with productionwells 512 may have been due to the placement of more production wells inthe formation. Placement of more production wells in the formation tendsto inhibit the buildup of pressure in the formation by producing atleast some hydrocarbons at an earlier time. Therefore, pressure buildupwas inhibited by producing at least some hydrocarbons at lowertemperatures (i.e., temperatures below pyrolysis temperatures).

[2121]FIGS. 346 and 347 illustrate coke deposition near heater wells.FIGS. 346 and 347 show a solid phase concentration (in m³ of soliddivided by m³ of liquid) at a heater well versus time (days). Plot 2350in FIG. 346 depicts the solid phase concentration at heater wells 520Aand 520B (FIG. 336) versus time. Plot 2352 in FIG. 347 depicts the solidphase concentration at heater wells 520K and 520L versus time. As shownin FIGS. 346 and 347, coke deposition was more significant at heaterwells in a bottom portion of the formation. This may have been due togravity drainage of liquid hydrocarbons towards the bottom of theformation, the residence time of liquid hydrocarbons in the bottom ofthe formation, and/or temperatures proximate heater wells in the bottomportion of the formation.

[2122] A large pattern simulation of an in situ process in a tar sandsformation was performed using a 3-D simulation (STARS). FIG. 348 depictsa pattern of heat sources 508 and production wells 512A-512E placed intar sands formation 2248 and used in the large pattern simulation. Heatsources 508 and production wells 512A-512E were placed horizontallywithin formation 2248 with a length of 1000 m. Formation 2248 had ahorizontal width of 145 m and a vertical height of 28 m. Five productionwells 512A-512E were placed within the pattern of heat sources 508 andwith the spacings as shown in FIG. 348.

[2123] A first stage of heating included turning on heat sources 508 infirst section 2354. Production during the first stage of heating wasthrough production well 512A in first section 2354. A minimum pressurefor production in production well 512A was set at 6.8 bars absolute.Fluids were produced through production well 512A as the fluids weremobilized and/or pyrolyzed within formation 2248. The first stage ofheating occurred for the first 360 days of the simulation.

[2124] A second stage of heating included turning on heat sources 508 insecond section 2356, third section 2358, fourth section 2360 and fifthsection 2362. Heat sources 508 in second section 2356, third section2358, fourth section 2360 and fifth section 2362 were turned on at 360days. Minimum pressure for production in production wells 512B-512E wasset at 6.8 bars absolute.

[2125] Heat sources 508 in first section 2354 were turned off at 1860days. At 1860 days, production through production well 512A was alsoshut off. Heat sources 508 in other sections 2356, 2358, 2360, 2362 weresimilarly turned off after 2200 days. The simulation ended at 2580 dayswith production through production wells 512B-512E remaining on. Heatsources 508 were maintained at a relatively constant heat output of 1150watts per meter. FIG. 349 depicts net heater output (J) versus time(days) for the simulation. Controlling the turning on and off of heatsources 508 produced the linear net heater output increase between about360 days and about 2200 days.

[2126] Production after the first stage of heating was through any oneof production wells 512A-512E. Because fluids were produced throughproduction well 512A at earlier times, fluids in the formation tended toflow towards production well 512A as the fluids were mobilized and/orpyrolyzed in other sections of formation 2248. Fluid flow was largelydue to vapor phase transport of fluids within formation 2248.

[2127]FIG. 350 depicts average temperature 2363 and average pressure2364 in fifth section 2362. As shown in FIG. 350, pressure 2364 began toincrease in fifth section 2362 after 360 days or when heat sources 508in the fifth section were turned on. A maximum average pressure in fifthsection remained below about 100 bars absolute around 800 days into thesimulation. Pressure then began to decrease as fluids were mobilizedwithin fifth section 2362 (i.e., the average temperature increased aboveabout 100° C.). The average temperature increased at a relativelyconstant rate from about 360 days until the heat sources were turned offat 2200 days. The maximum average temperature in the fifth section wasmaintained below about 400° C.

[2128]FIG. 351 depicts oil production rate (m³/day) versus time (days)as calculated in the simulation. As shown in FIG. 351, oil productionslowly increases for approximately the first 1500 days and thenincreased rapidly after about 1500 days to a maximum of about 880 m³/dayat about 1785 days. After about 1785 days, production rate decreased asa majority of fluids are produced from formation 2248. The highproduction rate at about 1785 days may be due to a high rate of vaporphase transport in the formation following pyrolysis of hydrocarbons inthe formation.

[2129]FIG. 352 depicts cumulative oil production (m³) versus time (days)as calculated in the simulation. As shown in FIG. 352, a majority ofcumulative oil production occurred between about 1000 days and about2200 days.

[2130]FIG. 353 depicts gas production rate (m³/day) versus time (days)as calculated in the simulation. As shown in FIG. 353, gas productionslowly increases for approximately the first 1500 days and thenincreased rapidly after about 1500 days to a maximum of about 235,000m³/day at about 1800 days. The maximum gas production rate occurred at asubstantially similar time to the maximum oil production rate shown inFIG. 351. Thus, the maximum oil production rate may be primarily due toa high gas production rate.

[2131]FIG. 354 depicts cumulative gas production (m³) versus time (days)as calculated in the simulation. As shown in FIG. 354, a majority ofcumulative gas production occurred between about 1000 days and about2200 days.

[2132]FIG. 355 depicts energy ratio (energy output in fluids versusenergy input from heat sources) versus time (days) as calculated in thesimulation. As shown in FIG. 355, the energy ratio increased during thefirst stage of heating as fluids are produced. After each successivestage of heating begins, there was an initial decrease in the energyratio. The energy ratio, however, continued to increase overall asfluids were produced from the formation during later stages of heating.

[2133]FIG. 356 depicts average density (kg/m³) of oil in the formationversus time (days). As shown in FIG. 356, the average density of oil inthe formation begins to decrease as the formation is heated. The densitymost likely decreases due to increased generation of vapors as theformation is heated. After about 1800 days, most oil is in the vaporphase and the density remains relatively constant with time.

[2134] Formation fluid produced from a hydrocarbon containing formationduring treatment may include a mixture of different components. Toincrease the economic value of products generated from the formation,formation fluid may be treated using a variety of treatment processes.Processes utilized to treat formation fluid may include distillation(e.g., atmospheric distillation, fractional distillation, and/or vacuumdistillation), condensation (e.g., fractional), cracking (e.g., thermalcracking, catalytic cracking, fluid catalytic cracking, hydrocracking,residual hydrocracking, and/or steam cracking), reforming (e.g., thermalreforming, catalytic reforming, and/or hydrogen steam reforming),hydrogenation, coking, solvent extraction, solvent dewaxing,polymerization (e.g., catalytic polymerization and/or catalyticisomerization), visbreaking, alkylation, isomerization, deasphalting,hydrodesulfurization, catalytic dewaxing, desalting, extraction (e.g.,of phenols, other aromatic compounds, etc.), and/or stripping.

[2135] Formation fluids may undergo treatment processes in a first insitu treatment area as the formation fluid is generated and produced, ina second in situ treatment area where a specific treatment processoccurs, and/or in surface treatment units. A “surface treatment unit” isa unit used to treat at least a portion of formation fluid at thesurface. Surface treatment units may include, but are not limited to,reactors (e.g., hydrotreating units, cracking units, ammonia generatingunits, fertilizer generating units, and/or oxidizing units), separationunits (e.g., recovery units, air separation units, liquid-liquidextraction units, adsorption units, absorbers, ammonia recovery and/orgenerating units, vapor/liquid separation units, distillation columns,reactive distillation columns, and/or condensing units), reboilingunits, heat exchange units, pumps, pipes, storage units, and/or energyproducing units (e.g., fuel cells and/or gas turbines). Multiple surfacetreatment units used in series, in parallel, and/or in a combination ofseries and parallel are referred to as a treatment facilityconfiguration. Treatment facility configurations may vary dramaticallydue to a composition of formation fluid as well as the products beinggenerated.

[2136] Surface treatment configurations may be combined with treatmentprocesses in various surface treatment systems to generate a multitudeof products. Products generated at a site may vary with local and/orglobal market conditions, formation characteristics, proximity offormation to a purchaser, and/or available feedstocks. Generatedproducts may be utilized on site, transferred to another site for use,and/or sold to a purchaser.

[2137] Feedstocks for surface treatment units may be generated intreatment areas and/or surface treatment units. A “feedstock” is astream containing at least one component required for a treatmentprocess. Feedstocks may include, but are not limited to, formationfluid, synthetic condensate, a gas stream, a water stream, a gasfraction, a light fraction, a middle fraction, a heavy fraction,bottoms, a naphtha fraction, a jet fuel fraction, a diesel fraction,and/or a fraction containing a specific component (e.g., heart fraction,phenols containing fraction, etc.). In some embodiments, feedstocks arehydrotreated prior to entering a surface treatment unit. For example, ahydrotreating unit used to hydrotreat a synthetic condensate maygenerate hydrogen sulfide to be utilized in the synthesis of afertilizer such as ammonium sulfate. Alternatively, one or morecomponents (e.g., heavy metals) may have been removed from formationfluids prior to entering the surface treatment unit.

[2138] In some embodiments, feedstocks for in situ treatment processesmay be generated at the surface in surface treatment units. For example,a hydrogen stream may be separated from formation fluid in a surfacetreatment unit and then provided to an in situ treatment area to enhancegeneration of upgraded products. In addition, a feedstock may beinjected into a treatment area to be stored for later use.Alternatively, storage of a feedstock may occur in storage units on thesurface.

[2139] The composition of products generated may be altered bycontrolling conditions within a treatment area and/or within one or moresurface treatment units. Conditions within the treatment area and/or oneor more surface treatment units which affect product compositioninclude, but are not limited to, average temperature, fluid pressure,partial pressure of H₂, temperature gradients, composition of formationmaterial, heating rates, and composition of fluids entering thetreatment area and/or the surface treatment unit. Many differenttreatment facility configurations exist for the synthesis and/orseparation of specific components from formation fluid.

[2140] Formation fluid may be produced from a formation through awellhead. As shown in FIG. 357, wellhead 1162 may separate formationfluid 2365 into gas stream 2366, liquid hydrocarbon condensate stream1772, and water stream 1774. Alternatively, formation fluid may beproduced from a formation through a wellhead and flow to a separationunit, where the formation fluid is separated into a gas stream, a liquidhydrocarbon condensate stream, and a water stream. A portion of the gasstream, the liquid hydrocarbon condensate stream, and/or the waterstream may flow to one or more surface treatment units for use in atreatment process. Alternatively, a portion of the gas stream, theliquid hydrocarbon condensate stream, and/or the water stream may beprovided to one or more treatment areas.

[2141] In some embodiments, formation fluid may flow directly from theformation to a surface treatment unit to be treated. An advantage oftreating formation fluid before separation may be a reduction in thenumber of surface treatment units required. Reducing the number ofsurface treatment units may result in decreased capital and/or operatingexpenses for a treatment system for formations.

[2142] Formation fluid may exit the formation at a temperature in excessof about 300° C. Utilizing thermal energy within the formation fluid mayreduce an amount of energy required by the treatment system. In certainembodiments, formation fluid produced at an elevated temperature may beprovided to one or more surface treatment units. Formation fluid mayenter the surface treatment unit at a temperature greater than about250° C., 275° C., 300° C., 325° C., or 350° C. Alternatively, thermalenergy from formation fluid may be transferred to other fluids utilizedby the treatment facility configuration and/or the in situ treatmentprocess.

[2143] As shown in FIG. 358, formation fluid 2365 produced from wellhead1162 may flow to heat exchange unit 2368. Heat exchange fluid 2370 mayflow into heat exchange unit 2368. Thermal energy from formation fluid2365 may be transferred to heat exchange fluid 2370 in heat exchangeunit 2368 to generate heated fluid 2372 and cooled formation fluid 2374.Heat exchange fluid 2370 may include any fluid stream produced from aformation (e.g., formation fluid, pyrolysis fluid, water, and/orsynthesis gas), and/or any fluid stream generated and/or separated outwithin a surface treatment unit (e.g., water stream, light fraction,middle fraction, heavy fraction, hydrotreated liquid hydrocarboncondensate stream, jet fuel stream, etc.).

[2144] In some in situ conversion process embodiments, a heat exchangeunit may be used to increase a temperature of the formation fluid anddecrease a temperature of the heat exchange fluid to generate a cooledfluid and a heated formation fluid. For example, pyrolysis fluids may beproduced from a first treatment area at a temperature of about 300° C.Synthesis gas may be produced from a second treatment area at atemperature of about 600° C. The pyrolysis fluids and synthesis gas mayflow in separate conduits to distant surface treatment units. Heat lossmay cause the pyrolysis fluids to condense before reaching a distantsurface treatment unit for treatment. Various configurations ofconduits, known in the art, may be used to form a heat exchange unit totransfer thermal energy from the synthesis gas to the pyrolysis fluidsto decrease, or prevent, condensation of the pyrolysis fluids.

[2145] In conventional treatment processes, hydrocarbon fluids producedfrom a formation may be separated into at least two streams, including agas stream and a synthetic condensate stream. The gas stream may containone or more components and may be further separated into componentstreams using one or more surface treatment units. The liquidhydrocarbon condensate stream, or synthetic condensate stream, maycontain one or more components that are separated using one or moresurface treatment units. In some embodiments, formation fluid may bepartially cooled to enhance separation of specific components. Forexample, formation fluid may flow to a heat exchange unit to reduce atemperature of the formation fluid. Then, the formation fluid may beprovided to a separation unit such as a distillation column and/or acondensing unit.

[2146] Formation fluid may be hydrotreated prior to separation into agas stream and a liquid hydrocarbon condensate stream. Alternatively,the gas stream and/or the liquid hydrocarbon condensate stream may behydrotreated in separate hydrotreating units prior to further separationinto component streams. “Synthetic condensate” is the liquid componentof formation fluid that condenses.

[2147] In an embodiment, synthetic condensate 2377 flows to treatmentfacilities, as shown in FIG. 359. Synthetic condensate 2377 may beseparated into several fractions in fractionator 2378. In someembodiments, synthetic condensate stream 2377 is separated into fourfractions. Light fraction 2380, middle fraction 2382, and heavy fraction2384 may flow to hydrotreating units 1830A, 1830B, 1830C. Hydrotreatingunits 1830A, 1830B, 1830C may upgrade hydrocarbons within fractions2380, 2382, and 2384 to form light fraction 2386, middle fraction 2388,and/or heavy fraction 2390. In addition, bottoms fraction 2392 may begenerated. Bottoms fraction 2392 may flow to an in situ treatment areaor a treatment facility for further processing. In some embodiments, theuse of a synthetic condensate stream from which sulfur containingcompounds have been removed, for example, by hydrotreating or aliquid-liquid extraction process, may increase an effective life of thehydrotreating units.

[2148] In an in situ conversion process embodiment, a fractionation unitmay separate a feedstock into a light fraction, a heart cut, a middlecut, and/or a heavy fraction. The composition of the heart cut may becontrolled by removing fluid for the heart cut at a point in thefractionator having a given temperature. After the heart cut has beenseparated, the heart cut may flow to one or more surface treatment unitsincluding, but not limited to, a hydrotreater, a reformer, a crackingunit, and/or a component recovery unit. For example, when a naphthalenefraction is desired, a heart cut may be taken from a point in thefractionator resulting in production of a stream having an atmosphericpressure true boiling point temperature greater than about 210° C. toless than about 230° C. This may correspond to the boiling point rangefor naphthalene. Components that can be separated from a syntheticcondensate in a “heart cut” may include, but are not limited to,mono-aromatic hydrocarbons (e.g., benzene, toluene, ethyl benzene,and/or xylene), naphthalene, anthracene, and/or phenols.

[2149] Temperatures at which components are separated from the formationfluid during distillation or condensation may be affected by theconcentration of water (e.g., steam) in the formation fluid. Steam maybe present in the formation fluid in varying concentrations, due tovarying water contents of formations and variations in steam generationduring treatment. In some embodiments, a steam content of formationfluid may be measured as the formation fluid is produced. The steamcontent may be used to adjust one or more operating conditions inseparation units to enhance separation of fractions.

[2150] Formation fluid may flow to one or more distillation columnspositioned in series to remove one or more fractions in succession. Theone or more fractions from the fluids may be used in one or more surfacetreatment units. “Serial fractional separation” is the removal of two ormore fractions from formation fluid in series. Some of the formationfluid flows to two or more separation units in series, and eachseparation unit may remove one or more components from the formationfluid. For example, formation fluid may be separated into a gas streamand a synthetic condensate. A “naphtha cut” may be separated from thesynthetic condensate. The “naphtha cut” may be further separated into a“phenols cut.” Separating successively smaller cuts from the formationfluid may allow the subsequent treatment units to be smaller and lesscostly, since only a portion of the formation fluid needs to be treatedto produce a specific product. In addition, molecular hydrogen may beseparated for use in one or more of the upstream or downstreamprocesses.

[2151]FIG. 360 depicts a serial fractional system. Synthetic condensate2377 may flow to separation unit 2394, where it is separated into two ormore fractions: light fraction 2396 and heavy fraction 2398. Lightfraction 2396 may flow to heat exchange unit 2400 to generate cooledlight fraction 2402, which is separated into light fraction 2404 inseparation unit 2406. Heat exchange unit 2408 may remove thermal energyfrom light fraction 2404 to cooled light fraction 2409, which then flowsto separation unit 2410. Naphtha fraction 2414 may be separated fromcooled light fraction 2409. Naphtha fraction 2414 may be furtherseparated into olefin generating compound fraction 2416 in separationunit 2418 after being cooled in heat exchange unit 2420 to form coolednaphtha fraction 2422. Olefin generating compound fraction 2416 may flowto an olefin generating unit to be converted to olefins. Fractions 2398,2424, 2426, 2428 may flow to one or more surface treatment units and/orin situ treatment areas for additional treatment. Extracting thermalenergy from fractions 2396, 2404, 2414, and/or 2416 may increase anenergy efficiency of the process by utilizing the heat in the fluids. Insome embodiments, light fractions (e.g., light fraction 2396, lightfraction 2404, and/or naphtha fraction 2414) may be heated in heatexchanging units 2400, 2408, 2420 prior to entering the one or moreseparation units.

[2152]FIG. 361 depicts a portion of a treatment facility embodiment usedto treat bottoms 2462. Some of heavy fractions 2398, 2424, 2426, 2428removed from separation units 2394, 2406, 2410, 2418 may flow toreboilers 2430, 2432, 2434, 2436. Recycle streams 2438, 2440, 2442, 2444may flow from reboilers 2430, 2432, 2434, 2436 to separation units 2394,2406, 2410, 2418 for further upgrading. In some embodiments, steam maybe provided to heavy fractions 2398, 2424, 2426, 2428 to form recyclestreams. In some embodiments, a separation system for treating formationfluid may include a combination of heat exchange units, reboilers,and/or the injection of steam.

[2153] In certain treatment facility embodiments, catalysts may be usedin separation units to upgrade hydrocarbons in formation fluid as thehydrocarbons are being separated into the various fractions. In someembodiments, reactive separation units may contain catalysts thatenhance hydrocarbon upgrading through hydrotreating. Molecular hydrogenpresent in the feedstock may be sufficient to hydrotreat hydrocarbonswithin the feedstock. In some embodiments, molecular hydrogen may beprovided to a feedstock entering a reactive separation unit or to thereactive separation unit to enhance hydrogenation.

[2154] Reactive distillation columns may be used to treat a syntheticcondensate such as synthetic condensate and/or hydrotreated syntheticcondensate in some embodiments. A reactive distillation column maycontain a catalyst to increase hydrotreating of hydrocarbons in fluidspassing through the reactive distillation column. In certainembodiments, the catalyst may be a conventional catalyst such as metalon an alumina substrate.

[2155] As illustrated in FIG. 362, multiple distillation columns 2446,2448, 2482, 2452 may be used to separate synthetic condensate 2377 intofractions. Distillation columns 2446, 2448, 2482, 2452 may containcatalyst 2454, which enables hydrocarbons within synthetic condensate2377 to be upgraded within distillation columns 2446, 2448, 2482, 2452through hydrotreating. Molecular hydrogen stream 1780 may be added todistillation columns 2446, 2448, 2482, 2452 to enhance hydrotreating ofhydrocarbons within synthetic condensate stream 2377 in distillationcolumns 2446, 2448, 2482, 2452. Molecular hydrogen stream 1780 may comefrom surface treatment units and/or produced formation fluids. Fractionsremoved from distillation column 2446 may include light fraction 2456,middle fraction 2458, heavy fraction 2460, and bottoms 2462.

[2156] In an embodiment, light fraction 2456 flows to separation unit2465 that separates light fraction 2456 into gaseous stream 2464, lightfraction 2466, and recycle stream 2468. Light fraction 2466 may flow toreactive distillation column 2448 to be separated and upgraded. Indistillation column 2448, light fraction 2466 may be converted intolight fraction 2467. A portion of light fraction 2467 may flow toreboiler 2470 and then flow to distillation column 2448 as recyclestream 2472. Light stream 2534 may flow to a surface treatment unit suchas a reforming unit, an olefin generating unit, a cracking unit, and/ora separation unit. The reforming unit may alter light stream 2534 togenerate aromatics and hydrogen. Alternatively, light stream 2534 may beused to generate various types of fuel (e.g., gasoline). Light stream2534 may, in certain embodiments, be blended with other hydrocarbonfluids to increase a value and/or a mobility of the hydrocarbon fluids.In some embodiments, light stream 2534 may be a naphtha stream.

[2157] In some embodiments, middle fraction 2458 flows into reactivedistillation column 2482. Middle fraction 2458 may be converted intomiddle fraction 2476 and recycle stream 2478 in reactive distillationcolumn 2482. Recycle stream 2478 may flow into distillation column 2446.A portion of middle fraction 2476 may flow into reboiler unit 2480 to bevaporized and enter distillation column 2482 as recycle stream 2484.Middle stream 2486 may be provided to a market and/or flow to a surfacetreatment unit for further treatment.

[2158] Heavy fraction 2460 may flow into distillation column 2452. Heavyfraction 2488 and recycle stream 2490 may be generated in reactivedistillation column 2452. Recycle stream 2490 may flow into distillationcolumn 2446. A portion of heavy fraction 2488 may flow into reboilerunit 2492 to be vaporized and enters distillation column 2452 as recyclestream 2494. Heavy stream 2496 may be provided to a market and/or flowto a surface treatment unit and/or in situ treatment area for furthertreatment.

[2159] Bottoms fraction 2462 may be removed from distillation column2446. A portion of bottoms fraction 2462 may be vaporized in reboilerunit 2498 and enter distillation column 2446 as recycle stream 2500.Bottoms stream 2502 may be cooled in heat exchange units. In certainembodiments, a portion of a bottoms fraction may be used as a feedstockfor an olefin plant and/or an in situ treatment area. In someembodiments, a portion of a bottoms fraction may flow to a hydrocrackingunit to form a transportation fuel stream.

[2160] In some embodiments, formation fluid produced from the ground maybe partially cooled to recover thermal energy from the fluid. Inaddition, formation fluid may be cooled to a temperature at which adesired component is removed from the formation fluid. Heat exchangingunits may remove thermal energy from the formation fluid such that atemperature within the formation fluid is reduced to a temperature atwhich one or more components are separated from formation fluid.Formation fluid may be provided to a distillation column where theformation fluid is further separated into a liquid stream and a vaporstream. The vapor stream may be provided to a heat exchanging unit toremove thermal energy from the vapor stream. The vapor stream may befurther separated in a distillation column. In some embodiments,multiple distillation columns may be arranged to separate the vaporstream into one or more fractions.

[2161] In some embodiments, formation fluid 2365 flows into condensingunit 2504 as shown in FIG. 363. Condensing unit 2504 may separateformation fluid 2365 into gas fraction 2506, light fraction 2508, heavyfraction 2510, and/or heart cut 2512. Gas fraction 2506, light fraction2508, heavy fraction 2510, and/or heart cut 2512 may flow to a surfacetreatment unit for additional treatment.

[2162] An example of a treatment facility configuration for treatingformation fluid is illustrated in FIG. 364. Formation fluid 2365 may beproduced through wellhead 1162 and cooled in one or more heat exchangeunits 2514. Cooled formation fluid 2516 may be condensed in condensingunit 2504 to form condensed formation fluid 2518. Condensed formationfluid 2518 may be separated in processing unit 2520 into gas stream 2522and synthetic condensate 2377. Gas stream 2522 may be compressed andseparated in compressor 1408 into gas stream 2524 and hydrocarboncontaining fluids 2526. Hydrocarbon containing fluids 2526 may be heatedin heater 2528. Heated hydrocarbon containing fluids 2530 may beseparated into gas stream 2532 and light stream 2534 in processing unit2536. Gas stream 2524 and gas stream 2532 may flow into expander 2538.Expander 2538 allows fluids within gas stream 2524 and gas stream 2532to expand into light off-gas 2540.

[2163] In an embodiment, synthetic condensate stream 2377 is pumped tohydrotreating unit 1830 to be hydrotreated. Hydrotreated syntheticcondensate stream 2542 may flow through heat exchange units 2514 to beheated. Heated and hydrotreated synthetic condensate stream 2544 may beseparated into a mixture of non-condensable hydrocarbons 2546 andhydrocarbon containing fluid 2548 in processing unit 2550. Hydrocarboncontaining fluid 2548 may be pumped through heat exchange units 2514 toform heated hydrocarbon containing fluid 2552. Heated hydrocarboncontaining fluid 2552 may be further heated in heating unit 2554 to formheated hydrocarbon containing fluid 2556. Heated hydrocarbon containingfluid 2556 and non-condensable hydrocarbons 2546 may be distilled indistillation column 2558 to form light fraction 2380, middle fraction2382, heavy fraction 2384, and bottoms 2560. Light fraction 2380 may becooled in heat exchange unit 2562. Cooled light fraction 2561 may beseparated into heavy off-gas 2564, water stream 2566, and hydrocarboncondensate stream 2568 in process unit 2570. Hydrocarbon condensatestream 2568 may be split into at least two streams, including recyclestream 2572 and light fraction 2573. Light fraction 2573 may be added tolight stream 2534. Olefins may be generated from light stream 2534 in areforming unit. Alternatively, light stream 2534 may be used to generatevarious types of fuel. Light stream 2534, in certain embodiments, may beblended with other hydrocarbon fluids to increase a value and/or amobility of the hydrocarbon fluids.

[2164] In some embodiments, middle fraction 2382 flows to distillationcolumn 2574. Recycle stream 2576 and middle fraction 2580 may begenerated in distillation column 2574. Recycle stream 2576 may flow todistillation column 2558. Reboiler 2578 may separate middle fraction2580 into recycle stream 2582 and hot middle fraction 2584. Recyclestream 2582 flows to distillation column 2574. Hot middle fraction 2584may be cooled in heat exchange unit 2586 to form cooled middle fraction2588. In addition, cooled middle fraction 2588 may flow into acondensing unit to form a middle stream. Alternatively, hot middlefraction 2584 may flow directly from reboiler 2578 to a condensing unitto form a middle stream.

[2165] In an embodiment, distillation column 2590 separates heavyfraction 2384 into recycle stream 2592 and heavy fraction 2595. Recyclestream 2592 may flow to distillation column 2558. Heavy fraction 2595may flow to reboiler 2594. Reboiler 2594 may separate heavy fraction2595 into recycle stream 2596 and heated heavy fraction 2598. Heatedheavy fraction 2598 may be cooled in heat exchange unit 2600 to formcooled heavy fraction 2602. In some embodiments, cooled heavy fraction2602 may flow into a condensing unit. Alternatively, heavy fraction 2598may flow from reboiler 2594 to a condensing unit to form a heavy stream.

[2166] In certain embodiments, bottoms fraction 2560 is removed fromdistillation column 2558 and is cooled in heat exchange unit 2604 toform cooled bottoms fraction 2606. In some embodiments, cooled bottomsfraction 2606 may flow into a condensing unit to form a condensate.Alternatively, bottoms fraction 2560 may flow directly from distillationcolumn 2558 to a condensing unit.

[2167] In some embodiments, distillation columns 2558, 2574, and/or 2590may contain catalysts to upgrade hydrocarbons. The catalysts may behydrotreating and/or cracking catalysts. In some embodiments, anadditional molecular hydrogen stream may be added to distillationcolumns 2558, 2574, and/or 2590 that contain such catalysts.

[2168] Formation fluid may contain substances that compromise surfacetreatment units by altering catalytic surfaces and/or by causingcorrosion. Many surface treatment units may require the removal of thesesubstances prior to treatment in the surface treatment unit. Componentsin formation fluid that may affect a life span and/or efficiency of thesurface treatment unit include heteroatoms (e.g., nitrogen, sulfur, andwater). For example, water decreases the catalytic ability ofconventional hydrotreating catalysts. In some embodiments, use of aconventional hydrotreating unit may require separation of water fromformation fluid prior to treatment. In addition, sulfur containingcompounds may cause corrosion of a surface treatment unit and decreasethe catalytic ability of certain catalysts used in the surface treatmentunit. Removal of sulfur containing compounds from formation fluid mayincrease the value of produced fluid and permit processing of the lowersulfur material in process units not designed for untreated producedfluid.

[2169] Components that foul or corrode surface treatment units may beremoved using a variety of methods including, but not limited to,hydrotreating, solvent extraction, a desalting process, and/orelectrostatic precipitation. In some embodiments, a portion of the waterpresent in formation fluid may be removed from formation fluid as theformation fluid is separated into a gas stream and a liquid hydrocarboncondensate stream.

[2170] In some embodiments, a desalting process may reduce salts information fluid and/or any water or fluid separated in a surfacetreatment unit. The desalting process may include, but is not limitedto, chemical separation, electrostatic separation, and/or filtration ofwater/fluid through a porous structure (e.g., water or fluid may befiltered through diatomaceous earth).

[2171] Heteroatoms may also be removed from formation fluid using anextraction process. Solvents may include, but are not limited to, aceticacid, sulfuric acid, and/or formic acid. Heteroatoms in acidic form,such as phenols and some sulfur compounds, may be removed by extractionwith basic solutions (e.g., caustic or aqueous ammonia). Extraction mayvary with a temperature of formation fluid and/or solvent, a solvent tooil ratio, and/or an acid strength of the acidic solvents. An effectivesolvent may be characterized by features including, but not limited to,inhibition of emulsion formation, immiscibility with feedstock, rapidphase separation, and/or high capacity. Removal of nitrogen containingcomponents by an extraction process may decrease hydrogen uptake and thehydrotreating severity required in subsequent hydrotreating units,thereby reducing operating and capital costs.

[2172] Enactment of more stringent regulatory standards for sulfur inhydrocarbon containing products may require a higher severity to removesulfur from the products. In some circumstances, sulfur may be removedfrom formation fluid prior to separating the fluid into streams tofacilitate removal of a maximum amount of sulfur. Similarly, formationfluid may be hydrotreated prior to separation into streams to decreasean overall cost of processing formation fluid. Subsequent sulfur removaland/or hydrotreating may further improve the quality of hydrocarbonfluids produced from the formation fluid.

[2173] Conventional refiners may not handle high concentrations ofheteroatoms in fluid fractions (e.g., naphtha, jet, and diesel).Hydrotreating may produce a product that would be acceptable to arefiner. Another approach, or a complementary approach, may be tooptimize the combination of the in situ conversion process conditionsand surface hydrotreating processes to obtain the highest product valuemix at the lowest total cost. For example, one in situ conversionprocess change that may improve properties of the liquid formation fluidis the use of backpressure on the formation during the heating process.Maintaining a fluid pressure by adjusting the backpressure may produce amuch lighter and more hydrogen rich product.

[2174] Hydrotreating a fluid may alter many properties of the fluid.Hydrotreating may increase the hydrogen content of the hydrocarbonswithin the fluid and/or the volume of fluid. In addition, hydrotreatingmay reduce a content of heteroatoms such as oxygen, nitrogen, or sulfurin the fluid. For example, nitrogen removed from the fluid duringhydrotreating may be converted into ammonia. Removed sulfur may beconverted into hydrogen sulfide. Feedstocks for hydrotreating units mayinclude, but are not limited to, formation fluid and/or any fluidgenerated or separated in a surface treatment unit (e.g., syntheticcondensate, light fraction, middle fraction, heavy fraction, bottoms,heart cut, pyrolysis gasoline, and/or molecular hydrogen generated at anolefin generating plant).

[2175] Olefins may be present in formation fluid as a result of in situtreatment processes. In some embodiments, olefin generating compoundsmay be produced in formation fluid. “Olefin generating compounds” arehydrocarbons having a carbon number equal to and/or greater than 2 andless than 30 (e.g., carbon numbers from 2 to 7). These olefin generatingcompounds may be converted into olefins, such as ethylene and propylene.Process conditions during treatment within a treatment area of aformation may be controlled to increase, or even to maximize, productionof olefins and/or olefin generating compounds within the formationfluid.

[2176] In an embodiment, olefins and/or olefin generating compoundsproduced in the formation fluid may be separated from the formationfluid using one or more treatment facility configurations. Separation ofolefins and/or olefin generating compounds from formation fluid mayoccur in, but is not limited to, a gas treating unit, a distillationunit, and/or a condensing unit. Olefin generating compounds may beseparated from formation fluid to form an olefin feedstock used togenerate olefins.

[2177] Olefin feedstocks may include formation fluid, syntheticcondensate, a naphtha stream, a heart cut (e.g., a stream containinghydrocarbons having carbon number from two to seven), a propane stream,and/or an ethane stream. For example, formation fluid may be separatedinto a liquid stream (e.g., synthetic condensate) and a gas stream. Thegas stream may be further separated into four or more fractions. Thefractions may include, but are not limited to, a methane fraction, amolecular hydrogen fraction, a gas fraction, and an olefin generatingcompound fraction. In some embodiments, olefin feedstocks may have beenhydrotreated and/or have had one or more components (e.g., arsenic,lead, mercury, etc.) removed prior to entering the olefin generatingunit.

[2178] Many different treatment facility configurations may produceolefins from an olefin feedstock. The particular configuration utilizedfor synthesis of olefins may depend on a type of formation treated, acomposition of formation fluid, and/or treatment process conditions usedin situ such as a temperature, a pressure, a partial pressure of H₂,and/or a rate of heating.

[2179] Conversion of formation fluid and/or olefin generating compoundsto olefins occurs when hydrocarbons in formation fluid are heatedrapidly to cracking temperatures and then quenched rapidly to inhibitsecondary reactions (e.g., recombination of hydrogen with olefins).Prolonged heating may result in the production of coke and, thus,quenching the reaction is vital to enhancing olefin generation. Atemperature required for olefin generation may be greater than about800° C. Formation fluid may exit the formation at a temperature greaterthan about 200° C. In certain embodiments, formation fluid may beproduced from wells containing a heat source such that a temperature ofat least a portion of the formation fluid is about 700° C. Therefore,additional heating may be required for generation of olefins. Formationfluid may flow to an olefin generating unit where fluid is initiallyheated and then cooled to quench the reaction to enhance production ofolefins.

[2180]FIG. 365 depicts an embodiment of treatment facility units used togenerate olefins from an olefin feedstock that contains olefingenerating compounds. The hydrogen content of hydrocarbons withinformation fluid may be increased to greater than about 12 weight % bycontrolling one or more conditions within a treatment area from whichformation fluid 2365 is produced. For example, maintaining a pressuregreater than about 7 bars (100 psig) and a temperature less than about375° C. within a treatment area may generate formation fluid havinghydrocarbons with a hydrogen content greater than about 12 weight %. Ahydrogen content of greater than 12 weight % in the hydrocarbons offormation fluid may decrease the content of heavy hydrocarbons and/orundesirable compounds in the formation fluid produced.

[2181] In an embodiment, formation fluid 2365 (e.g., formation fluidhaving hydrocarbons with a hydrogen content greater than about 12%)flows directly from wellhead 1162 into olefin generating unit 2608 to beconverted to olefin stream 2610. In some embodiments, the olefingenerating unit may be a steam cracker. Formation fluid 2365 may flowinto olefin generating unit 2608 at a temperature greater than about300° C. in certain embodiments. Thermal energy within the formationfluid may be utilized in the generation of olefins from the olefingenerating compounds. In an embodiment, formation fluid may containsteam. Steam in formation fluid may be utilized in the generation ofolefins. A portion of the steam required for the generation of olefinsin an olefin generating unit may be provided by steam present information fluid.

[2182] Alternatively, formation fluid may flow to a component removalunit prior to an olefin generating unit. In certain embodiments,formation fluid may include components containing small amounts of heavymetals such as arsenic, lead, and/or mercury. As depicted in FIG. 366,treatment unit 2612 may separate formation fluid 2365 into two componentstreams (e.g., streams 2614, 2616) and hydrocarbon containing fluids2618. Component streams 2614, 2616 may include a single component or amixture of multiple components. For example, treatment unit 2612 mayremove heavy metals in streams 2614, 2616. Hydrocarbon containing fluids2618 may flow to olefin generating unit 2608 to be converted to olefinstream 2610. Olefin stream 2610 may include, but is not limited to,ethylene, propylene, and/or butylene.

[2183] Molecular hydrogen within an olefin feedstock may be removed fromthe olefin feedstock prior to the feedstock being provided to an olefingenerating unit in some embodiments. In some embodiments, formationfluid may flow to a hydrotreating unit prior to flowing to an olefingenerating unit to convert at least a portion of the olefin generatingcompounds into olefins.

[2184] In an olefin generating unit, a portion of the formation fluidmay be converted into compounds which may include, but are not limitedto, olefins, molecular hydrogen, pyrolysis gasoline that contains BTEXcompounds (benzene, toluene, ethylbenzene and/or xylene), pyrolysispitch, and/or butadiene. In some embodiments, the molecular hydrogengenerated in the olefin generating unit may flow to a hydrotreating unitto hydrotreat fluids. For example, a portion of the generated molecularhydrogen may be used to hydrotreat pyrolysis gasoline and/or pyrolysispitch generated in the olefin generating unit. Alternatively, a portionof the generated molecular hydrogen may be provided to an in situtreatment area.

[2185] In some embodiments, a portion of fluid generated in an olefingenerating unit may flow to one or more extraction units to removecomponents such as butadiene and/or BTEX compounds. In some embodiments,pyrolysis gasoline generated in an olefin generating unit may have ahigh BTEX content. Pyrolysis gasoline may, in certain embodiments, beprovided to a surface treatment unit to remove the BTEX compounds. Insome embodiments, pyrolysis pitch may be used as a fuel. Alternatively,pyrolysis pitch may be provided to an in situ treatment area foradditional processing.

[2186] A steam cracking unit may be utilized as an olefin generatingunit as depicted in FIG. 367. Steam cracking unit 2620 may includeheating unit 2622 and quenching unit 2624. Olefin feedstock 2626entering heating unit 2622 may be heated to a temperature greater thanabout 800° C. Fluid 2628 may flow to quenching unit 2624 to rapidlyquench and compress fluid 2628. Fluid 2630 exiting quenching unit 2624may include one or more olefin compounds, molecular hydrogen, and/orBTEX compounds. The olefin compounds may include, but are not limitedto, ethylene, propylene, and/or butylene. In certain embodiments, fluid2630 may flow to a separation unit. The components within fluid 2630 maybe separated into component streams in the separation unit. Thecomponent streams may be sold, transported to a different facility,stored for later use, and/or utilized on site in treatment areas or insurface treatment units.

[2187] Ammonia may be generated during an in situ conversion process. Insitu ammonia may be generated during a pyrolysis stage from some of thenitrogen present in hydrocarbon material. Hydrogen sulfide may also beproduced within the formation from some of the sulfur present in thehydrocarbon containing material. The ammonia and hydrogen sulfidegenerated in situ may be dissolved in water condensed from the formationfluids.

[2188]FIG. 368 depicts a configuration of surface treatment units thatmay separate ammonia and hydrogen sulfide from water produced in theformation. Formation fluid 2365 may be separated at wellhead 1162 intogas stream 2366, synthetic condensate 2377, and water stream 1774. Gastreating unit 1796 may separate gas stream 2366 into gas mixture 2632,light hydrocarbon mixture 2634, and/or hydrogen fraction 2636. Gasmixture 2632 may include, but is not limited to, hydrogen sulfide,carbon dioxide, and/or ammonia. Gas mixture 2632 may be blended withwater stream 1774 to form aqueous mixture 2638. Aqueous mixture 2638 mayflow to stripping unit 2640, where aqueous mixture 2638 is separatedinto ammonia stream 2642 and aqueous mixture 2644. Aqueous mixture 2644may flow to stripping unit 2646 to be separated into hydrogen sulfidestream 1778 and water stream 2648. Ammonia stream 2642 may be stored asan aqueous solution or in anhydrous form. Alternately, ammonia stream2642 may be provided to surface treatment units requiring ammonia, suchas a urea synthesis unit or an ammonium sulfate synthesis unit.

[2189] In some embodiments, ammonia may be formed from nitrogen presentin hydrocarbons when fluids are being hydrotreated. The generatedammonia may also be separated from other components, as illustrated inFIG. 369. Synthetic condensate 2377 may flow to hydrotreating unit 1830to form ammonia containing stream 2650 and hydrotreated syntheticcondensate 2652. Ammonia containing stream 2650 may be blended withwater stream 1774 and gas mixture 2632 prior to entering stripping unit2640 as aqueous mixture 2654.

[2190] Alternatively, fluid containing small amounts or concentrationsof ammonia may flow to Claus treatment unit 2656 for treatment, asdepicted in FIG. 370. Wellhead 1162 may separate formation fluid 2365into gas stream 2366, synthetic condensate 2377, and water stream 1774.Gas treating unit 1796 may further separate gas stream 2366 into gasmixture 2632, light hydrocarbon mixture 2634, and/or hydrogen fraction2636. Water stream 1774 and gas mixture 2632 may be blended to formaqueous mixture 2638. Claus treatment unit 2656 may reduce ammonia inaqueous mixture 2638 to form fluid stream 2658. Recovered sulfur mayexit Claus treatment unit 2656 as sulfur stream 2660 and be utilized inany process that requires sulfur, either in treatment facilities ortreatment areas. In some embodiments, Claus treatment unit 2656 may alsogenerate a carbon dioxide stream. The carbon dioxide may be utilized ina urea synthesis unit. Alternatively, carbon dioxide may be provided toan in situ treatment area for sequestration.

[2191] If a hydrotreating unit is used, then at least a portion of thesulfur in the stream entering the hydrotreating unit may be converted tohydrogen sulfide. In some embodiments, hydrogen sulfide may be used tomake fertilizer, sulfuric acid, and/or converted to sulfur in a Claustreatment unit. Similarly, some nitrogen in the stream entering thehydrotreating unit may be converted to ammonia, which may also berecovered for sale and/or use in processes.

[2192] In some embodiments, ammonia may be generated on site in surfacetreatment units using an ammonia synthesis process as shown in FIG. 371.Air stream 1620 may flow to air separation unit 2662 to separatenitrogen stream 1540 and stream 2664 from air stream 1620. Nitrogenstream 1540 may be heated with heat exchange unit 2514 to form heatednitrogen feedstock 2666 prior to flowing into ammonia generating unit2668. Hydrogen feedstock 2670 may flow to ammonia generating unit 2668to react with nitrogen stream 1540 to form ammonia stream 2642. Ammoniagenerated during in situ or surface treatment processes may be stored inan aqueous solution or as anhydrous ammonia. In some instances, ammoniain either form may be sold commercially. Alternatively, ammonia may beused on site to generate a number of different products that havecommercial value (e.g., fertilizers such as ammonium sulfate and/orurea). Production of fertilizer may increase the economic viability of atreatment system used to treat a formation. Precursors for fertilizerproduction may be produced in situ or while treating formation fluid attreatment facilities.

[2193] Ammonia and carbon dioxide generated during treatment either insitu or at a surface treating unit may be used to generate urea for useas a fertilizer, as illustrated in FIG. 372. Ammonia stream 2642 andcarbon dioxide stream 1776 may react in urea generating unit 2672 toform urea stream 2674.

[2194] As illustrated in FIG. 373, ammonium sulfate may be generated bytreating formation fluid in a surface treatment unit. Wellhead 1162 mayseparate formation fluid 2365 into a mixture of non-condensablehydrocarbon fluids 2676 and synthetic condensate 2377. Separation unit2680 may be used to separate non-condensable hydrocarbon fluids 2676into hydrogen stream 1780, hydrogen sulfide stream 2682, methane stream2684, carbon dioxide stream 1776, and non-condensable hydrocarbon fluids2686.

[2195] Hydrogen sulfide stream 2682 may flow to oxidation unit 2688 tobe converted to sulfuric acid stream 2690. Additional hydrogen sulfidemay, in certain embodiments, be provided to oxidation unit 2688 fromhydrogen sulfide stream 2692. In some embodiments, hydrogen sulfidestream 2692 may be provided from a hydrotreating unit. The hydrotreatingunit may be a treatment facility in a different section of a treatmentsystem or part of a different configuration of a treatment system.

[2196] Air separation unit 2662 may be used to separate nitrogen stream1540 and stream 2664 from air stream 1620. Heat exchange unit 2514 mayheat nitrogen stream 1540 to form heated nitrogen feedstock 2666.Hydrogen stream 1780 and heated nitrogen feedstock 2666 may flow toammonia generating unit 2668 to form ammonia stream 2642. In someembodiments, additional hydrogen may be provided to ammonia generatingunit 2668. In some embodiments, a portion of hydrogen stream 1780 mayflow to an in situ treatment area and/or a surface treatment facility.In certain embodiments, process ammonia 2694, produced in formationfluid and/or generated in surface treatment units, is added to ammoniastream 2642 to form ammonia feedstock 2696.

[2197] Ammonia feedstock 2696 and sulfuric acid stream 2690 may flowinto fertilizer synthesis unit 2698 to produce ammonium sulfate stream2700. Alternatively, a portion of sulfuric acid produced in an oxidationunit may be sold commercially.

[2198] In some embodiments, ammonia produced during treatment of aformation may be used to generate ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea. Separated ammonia may beprovided to a stream containing carbon dioxide (e.g., synthesis gasand/or carbon dioxide separated from formation fluid) such that theseparated ammonia reacts with carbon dioxide in the stream to generateammonium carbonate, ammonium bicarbonate, ammonium carbamate, and/orurea. Utilization of separated ammonia in this manner may reduce carbondioxide emissions from a treatment process. Ammonium carbonate, ammoniumbicarbonate, ammonium carbamate, and/or urea may be commerciallymarketed to a local market for use (e.g., as a fertilizer or a materialto make fertilizer). Ammonium carbonate, ammonium bicarbonate, ammoniumcarbamate, and/or urea may capture or sequester carbon dioxide ingeologic formations.

[2199] In some embodiments, formation fluid may include a significantamount of phenols. The amount of phenols produced from a formationdepends on the amount of oxygenated aromatic hydrocarbons in thekerogenous materials in the formation. “Phenols” refers to aromaticrings with an attached OH group, including substituted aromatic ringssuch as cresol, xylenol, etc. The amount of phenols in producedformation fluid may depend on operating conditions in the formation(e.g., formation heating rate, temperature gradients in the formation,fluid pressure in the formation, partial pressure of molecular hydrogenin the formation, and/or an average temperature within the formation).Controlling one or more of these conditions may affect the carbondistribution in the formation fluid. As an average carbon distributionis lowered, a fraction having a carbon number greater than or equal to 6and a carbon number less than or equal to 8 may increase. This fractionmay correlate to the phenols fraction in the formation fluid.

[2200] In an embodiment, a method for treating a hydrocarbon containingformation in situ may include controlling a pressure of a selectedsection of the formation and/or the hydrogen partial pressure in theselected section of the formation such that production of phenols fromthe selected section is increased. For example, the amount of phenolstends to decrease as the pressure of the formation is increased and viceversa. The partial pressure of hydrogen in the formation may be changedby adding hydrogen to the formation or by adding a compound such assteam to the formation.

[2201] In certain embodiments, when the pressure (or partial pressure ofhydrogen) is increased, the production of phenol may also increase whilethe production of all phenols decreases. It is believed that some of thesubstituted groups from substituted aromatic rings (such as cresol,xylenol, etc.) may be replaced with hydrogen under higher pressures. Insome embodiments, a temperature and/or a heating rate may be controlledto increase the production of phenols from a selected section of theformation. The production of phenols may be increased such that a weightpercentage of phenols in a mixture produced from the selected section isgreater than about 30 weight % in the produced condensable hydrocarbonliquids (in certain types of coal). In certain embodiments, the weightpercentage of produced phenols from coal formations tends to be betweenabout 10-40 weight %o of the produced condensable hydrocarbon liquids asthe vitrinite reflectance of the formation varies from about 1.1 toabout 0.3. For example, in high volatile bituminous A coal the weightpercentage of produced phenols tends to be about 10-15 weight % in theproduced condensable hydrocarbon liquids, and for sub-bituminous C coalthe weight percent of produced phenols tends to be about 35-40 weight %in the produced condensable hydrocarbon liquids. Although the weightpercent of phenols varies between different types of coal, the totalamount of phenols produced tends to remain relatively constant since theamount of liquids produced tends to increase as the weight percent ofphenols in the liquids decreased.

[2202] Extraction of phenols from a hydrocarbon containing formation mayincrease the economic viability of an in situ treatment system.Separating phenols from formation fluid may increase the total value ofgenerated products. Phenols in a relatively concentrated form may have ahigher economic value than phenols as a component in formation fluid. Inaddition, removing phenols from formation fluid may reduce the cost ofhydrotreating by reducing hydrogen consumption (i.e., transformingoxygen and hydrogen to water) in hydrotreating units and/or reactors, aswell as reducing the volume of fluids being hydrotreated.

[2203] Formations may be selected for treatment due to the oxygencontent of a portion of the formation. The oxygen content of the portionmay be indicative of the phenols content producible from the portion.The formation or at least one portion thereof may be sampled todetermine the oxygen content in the formation.

[2204] In some embodiments, formation fluid may be provided to a phenolsextraction unit directly after production from a formation.Alternatively, formation fluid may be treated using one or more surfacetreatment units prior to flowing to a phenols extraction unit. Fluidsprovided to a phenols extraction unit may a “phenols rich” feedstock.The phenols rich feedstock may include, but is not limited to, formationfluid, synthetic condensate, a naphtha stream, and/or phenols richfractions.

[2205] Conditions within a treatment area of a formation may becontrolled to increase, or even maximize, production of phenols information fluid. FIG. 374 depicts surface treatment units used toseparate phenols from formation fluid 2365. Formation fluid may beseparated in phenols extraction unit 2702 into phenols fraction 2704 andfraction 2706. In some embodiments, phenols extraction unit 2702 mayutilize water-and/or methanol to extract phenols. In certainembodiments, phenols fraction 2704 may flow to purifying unit 2708.Purifying unit 2708 may generate phenols stream 2710. Phenols stream2710 may be sold commercially, stored on site, transported off site,and/or utilized in other treatment processes.

[2206] In some embodiments, the phenols extraction unit may separate aphenols rich feedstock into two or more streams. The two or more streamsmay include a hydrocarbon stream and/or a phenol stream. In addition,alternate streams which may be separated from the phenols rich feedstockin the phenols extraction unit may include, but are not limited to, aphenol stream, a cresol stream, a xylenol stream, a phenol-cresolstream, a cresol-xylenol stream, and/or any combination thereof. Forexample, the phenols rich feedstock may be separated into four streamsincluding a hydrocarbon stream, a phenol stream, a cresol stream, and axylenol stream.

[2207] In some embodiments, phenols may be recovered from a portion offormation fluid. Treating a portion of formation fluid may reducecapital and operating costs of a phenols extraction unit by reducing thevolume of fluids being treated. The portion of formation fluid providedto the phenols extraction unit may be a phenols rich feedstock (e.g.,synthetic condensate, light fraction, naphtha fraction, and/or phenolscontaining fraction). In the phenols extraction unit, the phenols richfraction may be separated into a phenols fraction and a hydrocarbonfraction. The phenols fraction may, in certain embodiments, flow to apurifying unit to remove one or more components.

[2208] Alternatively, phenols may be separated from formation fluid bycondensation and/or distillation of formation fluid to form a phenolscontaining fraction. The phenols containing fraction may include, but isnot limited to, a naphtha fraction, a phenols fraction, a phenolfraction, a cresol fraction, a phenol-cresol fraction, a xylenolfraction, and/or a cresol-xylenol fraction.

[2209] Molecular hydrogen may, in certain embodiments, be utilized toselectively convert phenols (e.g., xylenols) other than phenol withinthe phenols containing stream to achieve, a desired phenol content inthe generated fluid. For example, xylenols and cresols may be cracked inthe presence of molecular hydrogen to form phenol. Production of phenolfrom a mixture of xylenols is described in U.S. Pat. No. 2,998,457issued to Paulsen, et al., which is incorporated by reference as iffully set forth herein. These reactions may occur using hydrocrackingconditions in the presence of a catalyst containing approximately 10-15weight % chromia on a high purity low sodium content gamma type aluminasupport. Feedstocks generated as a result of an in situ conversionprocess may be subjected to the above described treatment process toincrease a content of phenol.

[2210] Formation fluid may include mono-aromatic components such asbenzene, toluene, ethyl benzene, and xylene, (i.e., BTEX compounds). Insome embodiments, separating BTEX compounds from formation fluid mayincrease an economic value of the generated products. Separated BTEXcompounds may have a higher economic value than the same BTEX compoundsin the mixture of component in the formation fluid. BTEX compounds maybe separated from a synthetic condensate stream. “Synthetic condensate”may refer to a liquid hydrocarbon condensate stream and/or ahydrotreated liquid condensate stream.

[2211] A process embodiment may include separating synthetic condensate2377 into BTEX compound stream 2712 and BTEX compound reduced syntheticcondensate 2714 using separation unit 2716, as illustrated in FIG. 375.Mono-aromatic reduced synthetic condensate 2714 may flow tohydrotreating unit 1830, where BTEX compound reduced syntheticcondensate 2714 is hydrotreated to form hydrotreated syntheticcondensate 2718. Hydrotreated synthetic condensate 2718 may flow to anysurface treatment unit for further treatment. Alternatively,mono-aromatic reduced synthetic condensate 2714 may, in certainembodiments, flow to a surface treatment unit for further treatment.

[2212] Mono-aromatic components, specifically BTEX compounds, may alsobe recovered after a synthetic condensate stream has been separated intoone or more fractions (e.g., a naphtha fraction, a jet fraction, and/ora diesel fraction). The naphtha fraction may be separated from formationfluid using a surface treatment unit. In some embodiments, removal ofBTEX compounds prior to hydrotreating the naphtha fraction may reducecapital and operating costs of a hydrotreating unit needed to treat thenaphtha fraction. In certain embodiments, a naphtha fraction may behydrotreated.

[2213] In some embodiments, formation fluid may contain BTEX generatingcompounds such as paraffins and/or naphthalene. BTEX generatingcompounds may flow to one or more surface treatment units to beconverted into BTEX compounds. In some embodiments, a syntheticcondensate may be hydrotreated and then separated in separation units toform a naphtha stream. The naphtha stream may be provided to a reformerunit that converts BTEX generating compounds to BTEX compounds.

[2214] Naphtha stream 2720 may flow to reforming unit 2722, asillustrated in FIG. 376. Naphtha stream 2720 may be converted intoreformate 2724 and hydrogen stream 1780. In certain embodiments,hydrogen stream 1780 flows to any surface treatment unit and/ortreatment area requiring hydrogen. For example, a hydrotreating unitand/or a reactive distillation column may utilize hydrogen stream 1780.Reformate 2724 may flow to recovery unit 2726. Reformate 2724 may beseparated into mono-aromatic stream 2728 and raffinate 2730 in recoveryunit 2726. In some embodiments, raffinate 2730 may flow to a processingunit to be converted to a gasoline stream. The gasoline may be providedto a local market. In some embodiments, a mono-aromatic recovery unitmay separate reformate 2724 into one or more streams, such as raffinate2730, a benzene stream, a toluene stream, an ethyl benzene stream,and/or a xylene stream. In certain embodiments, naphtha stream 2720 maybe replaced with a “heart cut” (i.e., products distilled in a relativelynarrow selected temperature range) corresponding to mono-aromaticcompounds.

[2215] Conversion of BTEX generating compounds into BTEX compounds inreforming unit 2722 may form molecular hydrogen. The molecular hydrogenmay be used in one or more surface treatment units and/or in situtreatment areas where molecular hydrogen is needed. An advantage ofutilizing a reforming unit may be the generation of molecular hydrogenfor use on site. Generating molecular hydrogen on site may lower capitalas well as operating costs for a given treatment system.

[2216] Formation fluid produced from hydrocarbon containing formationsduring an in situ conversion process may contain one or more components(e.g., naphthalene, anthracene, pyridine, pyrroles, and/or thiophene andits homologs). Various operating conditions within a treatment area maybe controlled to increase the production of a component. Some of thecomponents may be commercially viable products. Separating somecomponents from formation fluid may increase the total value ofgenerated products. A separated component in relatively concentratedform may have higher economic value than the same component in formationfluid. For example, formation fluid containing naphthalene may be soldat a lower price than a naphthalene stream separated from the formationfluid and the remaining formation fluid. In an embodiment, separation ofnaphthalenes may be accomplished using crystallization. In addition,removal of some components may reduce hydrogen consumption in subsequenthydrotreating units.

[2217]FIG. 377 depicts an embodiment of recovery unit 2732 used toseparate a component from heart cut 2734. Heart cut 2734 may be obtainedfrom a synthetic crude or formation fluid. Heart cut 2734 flows torecovery unit 2732, which may separate heart cut 2734 into componentstream 2736 and hydrocarbon mixture 2738. In some embodiments, componentstream 2736 may be sold and/or used on site in an in situ treatment areaand/or a surface treatment unit. Hydrocarbon mixture 2738 may flow toone or more treatment units for additional treatment or, in someembodiments, to an in situ treatment area.

[2218] In some embodiments, the recovery unit, as shown in FIG. 377,separates the component from a feedstock stream (e.g., formation fluid,synthetic condensate, a gas stream, a light fraction, a middle fraction,a heavy fraction, bottoms, a naphtha stream, a jet fuel stream, a dieselstream, etc). Recovery units may separate more than one component fromthe feedstock stream in certain embodiments. For example, a recoveryunit may separate a feedstock stream into a naphthalene stream, ananthracene stream, a naphthalene/anthracene stream, and/or a hydrocarbonmixture. Fluids generated during an in situ conversion process (e.g., ofa coal formation) may contain naphthalene and/or anthracene.

[2219] When nitrogen containing components (e.g., pyridines andpyrroles) are to be separated from a feedstock, the recovery unit may bea nitrogen extraction unit. In some embodiments, a nitrogen extractionunit may separate the nitrogen containing components using a sulfuricacid process or a formic acid process. Nitrogen extraction units mayinclude sulfuric acid extraction units and/or closed cycle formic acidextraction units. A sulfuric acid process may separate a portion of theformation fluid into a raffinate and an extract oil. The extract oil maycontain pyridines and other nitrogen containing compounds, as well asspent acid. The extract oil may be separated into a nitrogen richextract and an acid stream.

[2220] Shale oil produced from an in situ thermal conversion process mayhave major components in the desirable naphtha, jet, and diesel boilingrange. The shale oil, however, may also contain a significant amount ofnitrogen compounds. Methods to remove the nitrogen compounds include,but are not limited to, hydrotreating and/or solvent extraction. Studiesof various solvent extraction configurations were completed to determinethe optimal conditions and/or materials for removing nitrogen compoundsfrom oil produced during the in situ conversion process in an oil shaleformation.

[2221] A successful extraction process exhibits the followingproperties: inhibition of emulsion formation, immiscibility with thefeedstock, rapid phase separation, and high capacity. An initialscreening of the first three properties was used to direct laterstudies.

[2222] All the solvents tested during the initial screening developed adeep red color upon mixing with the shale oil, indicating that somecomponents from the shale oil were partitioned into the solvent. Afurther indication of extraction efficiency was an increase in solventvolume. In a perfectly selective system (e.g., where only thosemolecules containing nitrogen were removed), the volume gain would beabout 16%.

[2223] The initial screening studies were conducted using shale oil andfour solvents. Solvents evaluated included sulfuric acid, formic acid, 1-methyl-2-pyrrolidinone (NMP), and acetic acid. Extraction severity wasvaried by changing the acid strength, the temperature, and the solventto oil ratios. All experiments used 10 cm³ of a solvent/water mixtureand 10 cm³ of oil mixed at room temperature for 1 minute in a 14 g vial(8 dram vial).

[2224] In the initial screening using acetic acid, only the experimentusing 100% acetic acid resulted in an increase in volume with noemulsion formation and a reasonable separation time of approximately 15minutes. Concentrations of acetic acid greater than 30 weight %increased the required extract volume, and no emulsions were formed.Phase separation times ranging from approximately 5 to 10 minutes wereacceptable. Sulfuric acid was the next solvent tested. Whenconcentrations of sulfuric acid were less than 70 weight %, an emulsionformed. At higher concentrations, however, the light color of theraffinate indicated that a large percentage of the polynuclear aromaticcompounds, including nitrogen compounds, were extracted. The finalsolvent tested in the initial screening was 1-methyl-2-pyrrolidinone(NMP). Extractions using concentrations greater than 90 weight % NMP hadan increase in extract volume as well as no emulsion formation. Thephase separation time, however, ranged from 45 to 240 minutes.

[2225] The initial study determined a range of concentrations for eachsolvent for which there was an increase in extract volume, no emulsionformation, and reasonable phase separation times. The solventconcentrations included greater than 30 weight % formic acid, greaterthan 70 weight % sulfuric acid, greater than 30 weight % NMP, and 100%acetic acid.

[2226] Experiments were performed in a batch mode using 1 L or 2 Lseparatory funnel 2740, as shown in FIG. 378. Weighed amounts of solvent2742 and water 1524 were mixed and added to separatory funnel 2740,followed by shale oil 2744. The total volumes were usually in the rangeof 500-800 mL for the 1 L experiments and about 1200-1600 mL for the 2 Lexperiments. For extractions performed at elevated temperatures, thesolvent and oil were equilibrated for 40 minutes in a 19 L (5 gallon)metal can filled with water that was heated to the desired temperature.The mixture was vigorously shaken for 1 minute and then allowed to phaseseparate. In most cases, 30 minutes were allowed for separation intoraffinate 2746 and solvent layer 2748, but in some cases (e.g., withsulfuric acid), the phase separation was much quicker.

[2227] Some experiments, called “crosscurrent contacting,” involved aseries of sequential contacting steps. For example, in a two-stepcrosscontacting, the raffinate phase from the first contact would becontacted with a second aliquot of fresh solvent. The overallsolvent/oil ratio reported reflects the total volume of solvent used forall contacts.

[2228] To evaluate the suitability of the extracted oil as a feedstockfor a refinery, a large sample was prepared and distilled into fourproduct cuts. Based on initial 1 L studies, the optimum formic acidconcentration was 85.3 weight %. Five crosscurrent extractions werecarried out with an overall solvent to oil ratio of 0.65. The raffinateproducts were combined prior to distillation.

[2229] The first solvent tested was 1-methyl-2-pyrrolidinone (NMP). Theraffinate fraction generated contained a higher weight percentage, andin some cases a significantly higher weight percentage, of nitrogencompounds than the feedstock. The solubility of the NMP in the oil phasewas significant. Consequently, as the nitrogen compounds in shale oilwere extracted into the NMP, some of the NMP was partitioned into theraffinate layer. With concentrations greater than 90 weight %, anincrease in extract volume was observed as well as no emulsionformation, however, the phase separation time ranged from 45 to 240minutes.

[2230] The acetic acid extraction using a 99.9 weight % acetic acidsolution exhibited 88.4 weight % nitrogen compound removal and 88 weight% raffinate yield. A crosscurrent experiment indicated, however, thatsome acetic acid was partitioned into the raffinate layer.

[2231] Preliminary experiments with formic acid were carried out at 40°C with a 1 L glass separatory funnel. A temperature of 40° C. wasinitially chosen as a value close to the highest temperature that couldbe used in an atmospheric extraction, since the initial boiling point ofthe oil was about 50° C. Higher extraction temperatures may haveresulted in significant losses of oil in these simple extractionstudies.

[2232] Acid concentrations were initially varied between 85-88 weight %,and both single step and crosscurrent extractions were investigated. Theraffinate yields varied between 82-87 weight % and the level of nitrogenextraction varied between 90-92 weight %. The results exceeded thetarget of greater than 90 weight % nitrogen removal with an oil yieldgreater than 83 weight %.

[2233] Based on the initial studies, five extractions were conductedusing a 2 L separatory funnel. The total amount of oil extracted was 4.0L. The acid concentration was 85.4 weight %, and each extraction wascarried out in crosscurrent fashion with three contacts of fresh acidwith the oil. The average nitrogen compound removal was 92 weight % (880ppm), and the overall raffinate oil yield was 83.7 weight %. Theraffinate product was distilled into four fractions: naphtha (20.2weight %), jet (37.1 weight %), diesel (26.3 weight %), and residue(15.2 weight %). In addition, there was approximately 1 weight % oflight material that appeared to be primarily formic acid. While over 90weight % of the nitrogen compounds were removed, some nitrogen compoundsremained in each of the fractions. The naphtha fraction contained about70 ppm nitrogen. The high jet smoke point of 20 mm and cetane index of55 for the diesel indicated that commercial products could be made fromthese two fractions.

[2234] A simpler process with no acid recycle was also examined usingsulfuric acid as the solvent. A series of experiments was carried out toexamine extraction efficiency. With a solvent to oil ratio of 0.074 andan acid concentration of 93 weight %, the sulfuric acid removed 97weight % of the nitrogen compounds (229 ppm product nitrogen), and theraffinate yield was 82 weight %. Higher sulfuric acid/oil ratiosextracted more nitrogen compounds. A 90 weight % sulfuric acidconcentration with an acid/oil ratio of 1.0 removed 99.8 weight %nitrogen compounds (27 ppm product nitrogen), with a yield of 76 weight%. Lower acid concentrations removed fewer nitrogen compounds.

[2235] Sulfuric acid extractions with a solvent to oil ratio of 0.074and a single contacting of 93 weight % sulfuric acid removed 97 weight %of the nitrogen compounds. The raffinate oil yield was 82 weight %. Theformic acid experiments required higher concentrations of acid toextract the nitrogen compounds compared to sulfuric acid. Contacting theoil at room temperature with a 94 weight % formic acid solvent using asolvent to oil ratio of 1.0 removed 92 weight % of the nitrogencompounds from the oil and resulted in an oil yield of 86 weight %.

[2236] Removal of greater than 90% of the nitrogen compounds andmaintaining an oil yield greater than 83 weight % was achieved with twoof the solvents tested, specifically sulfuric acid and formic acid. Thesulfuric acid extractions required low solvent to oil ratios to achievethe desired nitrogen compound removal. Contacting the oil with 93 weight% sulfuric acid solvent using a solvent to oil ratio of 0.074, 97 weight% of the nitrogen compounds were removed and the raffinate oil yield was82 weight %. With a single room temperature contacting of 94 weight %formic acid at a 1.0 solvent to oil ratio, 92 weight % of nitrogencompounds were removed.

[2237]FIG. 379 depicts an embodiment of treatment areas 2750 surroundedby perimeter barrier 2752. Each treatment area 2750 may be a volume offormation that is, or is to be, subjected to an in situ conversionprocess. Perimeter barrier 2752 may include installed portions andnaturally occurring portions of the formation. Naturally occurringportions of the formation that form part of a perimeter barrier mayinclude substantially impermeable layers of the formation. Examples ofnaturally occurring perimeter barriers include overburdens andunderburdens. Installed portions of perimeter barrier 2752 may be formedas needed to define separate treatment areas 2750. In situ conversionprocess (ICP) wells 2754 may be placed within treatment areas 2750. ICPwells 2754 may include heat sources, production wells, treatment areadewatering wells, monitor wells, and other types of wells used during insitu conversion.

[2238] Different treatment areas 2750 may share common barrier sectionsto minimize the length of perimeter barrier 2752 that needs to beformed. Perimeter barrier 2752 may inhibit fluid migration intotreatment area 2750 undergoing in situ conversion. Advantageously,perimeter barrier 2752 may inhibit formation water from migrating intotreatment area 2750. Formation water typically includes water anddissolved material in the water (e.g., salts). If formation water wereallowed to migrate into treatment area 2750 during an in situ conversionprocess, the formation water might increase operating costs for theprocess by adding additional energy costs associated with vaporizing theformation water and additional fluid treatment costs associated withremoving, separating, and treating additional water in formation fluidproduced from the formation. A large amount of formation water migratinginto a treatment area may inhibit heat sources from raising temperatureswithin portions of treatment area 2750 to desired temperatures.

[2239] Perimeter barrier 2752 may inhibit undesired migration offormation fluids out of treatment area 2750 during an in situ conversionprocess. Perimeter barriers 2752 between adjacent treatment areas 2750may allow adjacent treatment areas to undergo different in situconversion processes. For example, a first treatment area may beundergoing pyrolysis, a second treatment area adjacent to the firsttreatment area may be undergoing synthesis gas generation, and a thirdtreatment area adjacent to the first treatment area and/or the secondtreatment area may be subjected to an in situ solution mining process.Operating conditions within the different treatment areas may be atdifferent temperatures, pressures, production rates, heat injectionrates, etc.

[2240] Perimeter barrier 2752 may define a limited volume of formationthat is to be treated by an in situ conversion process. The limitedvolume of formation is known as treatment area 2750. Defining a limitedvolume of formation that is to be treated may allow operating conditionswithin the limited volume to be more readily controlled. In someformations, a hydrocarbon containing layer that is to be subjected to insitu conversion is located in a portion of the formation that ispermeable and/or fractured. Without perimeter barrier 2752, formationfluid produced during in situ conversion might migrate out of the volumeof formation being treated. Flow of formation fluid out of the volume offormation being treated may inhibit the ability to maintain a desiredpressure within the portion of the formation being treated. Thus,defining a limited volume of formation that is to be treated by usingperimeter barrier 2752 may allow the pressure within the limited volumeto be controlled. Controlling the amount of fluid removed from treatmentarea 2750 through pressure relief wells, production wells and/or heatsources may allow pressure within the treatment area to be controlled.In some embodiments, pressure relief wells are perforated casings placedwithin or adjacent to wellbores of heat sources that have sealedcasings, such as flameless distributed combustors. The use of some typesof perimeter barriers (e.g., frozen barriers and grout walls) may allowpressure control in individual treatment areas 2750.

[2241] Uncontrolled flow or migration of formation fluid out oftreatment area 2750 may adversely affect the ability to efficientlymaintain a desired temperature within treatment area 2750. Perimeterbarrier 2752 may inhibit migration of hot formation fluid out oftreatment area 2750. Inhibiting fluid migration through the perimeter oftreatment area 2750 may limit convective heat losses to heat loss influid removed from the formation through production wells and/or fluidremoved to control pressure within the treatment area.

[2242] During in situ conversion, heat applied to the formation maycause fractures to develop within treatment area 2750. Some of thefractures may propagate towards a perimeter of treatment area 2750. Apropagating fracture may intersect an aquifer and allow formation waterto enter treatment area 2750. Formation water entering treatment area2750 may not permit heat sources in a portion of the treatment area toraise the temperature of the formation to temperatures significantlyabove the vaporization temperature of formation water entering theformation. Fractures may also allow formation fluid produced during insitu conversion to migrate away from treatment area 2750.

[2243] Perimeter barrier 2752 around treatment area 2750 may limit theeffect of a propagating fracture on an in situ conversion process. Insome embodiments, perimeter barriers 2752 are located far enough awayfrom treatment areas 2750 so that fractures that develop in theformation do not influence perimeter barrier integrity. Perimeterbarriers 2752 may be located over 10 m, 40 m, or 70 m away from ICPwells 2754. In some embodiments, perimeter barrier 2752 may be locatedadjacent to treatment area 2750. For example, a frozen barrier formed byfreeze wells may be located close to heat sources, production wells, orother wells. ICP wells 2754 may be located less than 1 m away fromfreeze wells, although a larger spacing may advantageously limitinfluence of the-frozen barrier on the ICP wells, and limit theinfluence of formation heating on the frozen barrier.

[2244] In some perimeter barrier embodiments, and especially for naturalperimeter barriers, ICP wells 2754 may be placed in perimeter barrier2752 or next to the perimeter barrier. For example, ICP wells 2754 maybe used to treat hydrocarbon layer 522 that is a thin rich hydrocarbonlayer. The ICP wells may be placed in overburden 524 and/or underburden914 adjacent to hydrocarbon layer 522, as depicted in FIG. 380. ICPwells 2754 may include heater-production wells that heat the formationand remove fluid from the formation. Thin rich layer hydrocarbon layer522 may have a thickness greater than about 0.2 m and less than about 8m, and a richness of from about 205 liters of oil per metric ton toabout 1670 liters of oil per metric ton. Overburden 524 and underburden914 may be portions of perimeter barrier 2752 for the in situ conversionsystem used to treat rich thin layer 522. Heat losses to overburden 524and/or underburden 914 may be acceptable to produce rich hydrocarbonlayer 522. In other ICP well placement embodiments for treating thinrich hydrocarbon layers 522, ICP wells 2754 may be placed within thethin hydrocarbon layer or hydrocarbon layers, as depicted in FIG. 381.

[2245] In some in situ conversion process embodiments, a perimeterbarrier may be self-sealing. For example, formation water adjacent to afrozen barrier formed by freeze wells may freeze and seal the frozenbarrier should the frozen barrier be ruptured by a shift or fracture inthe formation. In some in situ conversion process embodiments, progressof fractures in the formation may be monitored. If a fracture that ispropagating towards the perimeter of the treatment area is detected, acontrollable parameter (e.g., pressure or energy input) may be adjustedto inhibit propagation of the fracture to the surrounding perimeterbarrier.

[2246] Perimeter barriers may be useful to address regulatory issuesand/or to insure that areas proximate a treatment area (e.g., watertables or other environmentally sensitive areas) are not substantiallyaffected by an in situ conversion process. The formation within theperimeter barrier may be treated using an in situ conversion process.The perimeter barrier may inhibit the formation on an outer side of theperimeter barrier from being affected by the in situ conversion processused on the formation within the perimeter barrier. Perimeter barriersmay inhibit fluid migration from a treatment area. Perimeter barriersmay inhibit rise in temperature to pyrolysis temperatures on outer sidesof the perimeter barriers.

[2247] Different types of barriers may be used to form a perimeterbarrier around an in situ conversion process treatment area. Theperimeter barrier may be, but is not limited to, a frozen barriersurrounding the treatment area, dewatering wells, a grout wall formed inthe formation, a sulfur cement barrier, a barrier formed by a gelproduced in the formation, a barrier formed by precipitation of salts inthe formation, a barrier formed by a polymerization reaction in theformation, sheets driven into the formation, or combinations thereof.

[2248]FIG. 382 depicts a side representation of a portion of anembodiment of treatment area 2750 having perimeter barrier 2752 formedby overburden 524, underburden 914, and freeze wells 2756 (only onefreeze well is shown in FIG. 382). A portion of freeze well 2756 andperimeter barrier 2752 formed by the freeze well may extend intounderburden 914. Portions of heat sources and portions of productionwells may pass through a low temperature zone formed by the freezewells. In some embodiments, perimeter barrier 2752 may not extend intounderburden 914 (e.g., a perimeter barrier may extend into hydrocarbonlayer 522 reasonably close to the underburden or some of the hydrocarbonlayer may function as part of the perimeter barrier). Underburden 914may be a rock layer that inhibits fluid flow into or out of treatmentarea 2750. In some embodiments, a portion of the underburden may behydrocarbon containing material that is not to be subjected to in situconversion.

[2249] Overburden 524 may extend over treatment area 2750. Overburden524 may include a portion of hydrocarbon containing material that is notto be subjected to in situ conversion. Overburden 524 may inhibit fluidflow into or out of treatment area 2750.

[2250] Some formations may include underburden 914 that is permeable orincludes fractures that would allow fluid flow into or out of treatmentarea 2750. A portion of perimeter barrier 2752 may be formed belowtreatment area 2750 to inhibit inflow of fluid into the treatment areaand/or to inhibit outflow of formation fluid during in situ conversion.FIG. 383 depicts treatment area 2750 having a portion of perimeterbarrier 2752 that is below the treatment area. The perimeter barrier maybe a frozen barrier formed by freeze wells 2756. In some embodiments, aperimeter barrier below a treatment area may follow along a geologicalformation (e.g., along dip of a dipping coal formation).

[2251] Some formations may include overburden 524 that is permeable orincludes fractures that allow fluid flow into or out of treatment area2750. A portion of perimeter barrier 2752 may be formed above thetreatment area to inhibit inflow of fluid into the treatment area and/orto inhibit outflow of formation fluid during in situ conversion. FIG.383 depicts an embodiment of an in situ conversion process having aportion of perimeter barrier 2752 formed above treatment area 2750. Insome embodiments, a perimeter barrier above a treatment area may followalong a geological formation (e.g., along dip of a dipping formation).In some embodiments, a perimeter barrier above a treatment area may beformed as a ground cover placed at or near the surface of the formation.Such a perimeter barrier may allow for treatment of a formation whereina hydrocarbon layer to be processed is close to the surface.

[2252] In some formations, water may flow through a fracture system in ahydrocarbon containing formation. For example, a coal seam may belocated between an impermeable overburden and an impermeableunderburden. The coal seam may include a water saturated fracturesystem. Water may flow through the fracture system of the coal seam.Perimeter barriers may be inserted through the overburden, through thecoal seam, and into the underburden to form a treatment area. Theinserted perimeter barrier, the overburden, and the underburden may formperimeter barriers that define a treatment area.

[2253] As depicted in FIG. 379, several perimeter barriers 2752 may beformed to divide a formation into treatment areas 2750. If a largeamount of water is present in the hydrocarbon containing material,dewatering wells may be used to remove water in the treatment area aftera perimeter barrier is formed. If the hydrocarbon containing materialdoes not contain a large amount of water, heat sources may be activated.The heat sources may vaporize water within the formation, and the watervapor may be removed from the treatment area through production wells.

[2254] A perimeter barrier may have any desired shape. In someembodiments, portions of perimeter barriers may follow along geologicalfeatures and/or property lines. In some embodiments, portions ofperimeter barriers may have circular, square, rectangular, or polygonalshapes. Portions of perimeter barriers may also have irregular shapes. Aperimeter barrier having a circular shape may advantageously enclose alarger area than other regular polygonal shapes that have the sameperimeter. For example, for equal perimeters, a circular barrier willenclose about 27% more area than a square barrier. Using a circularperimeter barrier may require fewer wells and/or less material toenclose a desired area with a perimeter barrier than would other regularperimeter barrier shapes. In some embodiments, square, rectangular orother polygonal perimeter barriers are used to conform to property linesand/or to accommodate a regular well pattern of heat sources andproduction wells.

[2255] A formation that is to be treated using an in situ conversionprocess may be separated into several treatment areas by perimeterbarriers. FIG. 379 depicts an embodiment of a perimeter barrierarrangement for a portion of a formation that is to be processed usingsubstantially rectangular treatment areas 2750. A perimeter barrier fortreatment area 2750 may be formed when needed. The complete pattern ofperimeter barriers for all of the formation to be subjected to in situconversion does not need to be formed prior to treating individualtreatment areas.

[2256] Perimeter barriers having circular or arced portions may beplaced in a formation in a regular pattern. Centers of the circular orarced portions may be positioned at apices of imaginary polygonpatterns. For example, FIG. 384 depicts a pattern of perimeter barrierswherein a unit of the pattern is based on an equilateral triangle. FIG.385 depicts a pattern of perimeter barriers wherein a unit of thepattern is based on a square. Perimeter barrier patterns may also bebased on higher order polygons.

[2257]FIG. 384 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 2750 in a formation. Centers ofarced portions of perimeter barriers 2752 are positioned at apices ofimaginary equilateral triangles. The imaginary equilateral triangles aredepicted as dashed lines. First circular barrier 2752A may be formed inthe formation to define first treatment area 2750A.

[2258] Second barrier 2752B may be formed. Second barrier 2752B andportions of first barrier 2750A may define second treatment area 2750B.Second barrier 2752B may have an arced portion with a radius that issubstantially equal to the radius of first circular barrier 2752A. Thecenter of second barrier 2752B may be located such that if the secondbarrier were formed as a complete circle, the second barrier wouldcontact the first barrier substantially at a tangent point. Secondbarrier 2752B may include linear sections 2758 that allow for a largerarea to be enclosed for the same or a lesser length of perimeter barrierthan would be needed to complete the second barrier as a circle. In someembodiments, second barrier 2752B may not include linear sections andthe second barrier may contact the first barrier at a tangent point orat a tangent region. Second treatment area 2750B may be defined byportions of first circular barrier 2752A and second barrier 2752B. Thearea of second treatment area 2750B may be larger than the area of firsttreatment area 2750A.

[2259] Third barrier 2752C may be formed adjacent to first barrier 2752Aand second barrier 2752B. Third barrier 2752C may be connected to firstbarrier 2752A and second barrier 2752B to define third treatment area2750C. Additional barriers may be formed to form treatment areas forprocessing desired portions of a formation.

[2260]FIG. 385 depicts a plan view representation of a perimeter barrierembodiment that forms treatment areas 2750 in a formation. Centers ofarced portions of perimeter barriers 2752 are positioned at apices ofimaginary squares. The imaginary squares are depicted as dashed lines.First circular barrier 2752A may be formed in the formation to definefirst treatment area 2750A. Second barrier 2752B may be formed around aportion of second treatment area 2750B. Second barrier 2752B may have anarced portion with a radius that is substantially equal to the radius offirst circular barrier 2752A. The center of second barrier 2752B may belocated such that if the second barrier were formed as a completecircle, the second barrier would contact the first barrier at a tangentpoint. Second barrier 2752B may include linear sections 2758 that allowfor a larger area to be enclosed for the same or a lesser length ofperimeter barrier than would be needed to complete the second barrier asa circle. Two additional perimeter barriers may be formed to complete aunit of four treatment areas.

[2261] In some embodiments, central area 2760 may be isolated byperimeter barrier 2752. For perimeter barriers based on a squarepattern, such as the perimeter barriers depicted in FIG. 385, centralarea 2760 may be a square. A length of a side of the square may be up toabout 0.586 times a radius of an arc section of a perimeter barrier.Treatment facilities, or a portion of the treatment facilities, used totreat fluid removed from the formation may be located in central area2760. In other embodiments, perimeter barrier segments that form acentral area may not be installed.

[2262]FIG. 386 depicts an embodiment of a barrier configuration in whichperimeter barriers 2752 are formed radially about a central point. In anembodiment, treatment facilities for processing production fluid removedfrom the formation are located within central area 2760 defined by firstbarrier 2752A. Locating the treatment facilities in the center mayreduce the total length of piping needed to transport formation fluid tothe treatment facilities. In some embodiments, ICP wells are installedin the central area and treatment facilities are located outside of thepattern of barriers.

[2263] A ring of formation between second barrier 2752B and firstbarrier 2752A may be treatment area 2750A. Third barrier 2752C may beformed around second barrier 2752B. The pattern of barriers may beextended as needed. A ring of formation between an inner barrier and anouter barrier may be a treatment area. If the area of a ring is toolarge to be treated as a whole, linear sections 2758 extending from the,inner barrier to the outer barrier may be formed to divide the ring intoa number of treatment areas. In some embodiments, distances betweenbarrier rings may be substantially the same. In other embodiments, adistance between barrier rings may be varied to adjust the area enclosedby the barriers.

[2264] In some embodiments of in situ conversion processes, formationwater may be removed from a treatment area before, during, and/or afterformation of a barrier around the formation. Heat sources, productionwells, and other ICP wells may be installed in the formation before,during, or after formation of the barrier. Some of the production wellsmay be coupled to pumps that remove formation water from the treatmentarea. In other embodiments, dewatering wells may be formed within thetreatment area to remove formation water from the treatment area.Removing formation water from the treatment area prior to heating topyrolysis temperatures for in situ conversion may reduce the energyneeded to raise portions of the formation within the treatment area topyrolysis temperatures by eliminating the need to vaporize all formationwater initially within the treatment area.

[2265] In some embodiments of in situ conversion processes, freeze wellsmay be used to form a low temperature zone around a portion of atreatment area. “Freeze well” refers to a well or opening in a formationused to cool a portion of the formation. In some embodiments, thecooling may be sufficient to cause freezing of materials (e.g.,formation water) that may be present in the formation. In otherembodiments, the cooling may not cause freezing to occur; however, thecooling may serve to inhibit the flow of fluid into or out of atreatment area by filling a portion of the pore space with liquid fluid.

[2266] In some embodiments, freeze wells may be used to form a sideperimeter barrier, or a portion of a side perimeter barrier, in aformation. In some embodiments, freeze wells may be used to form abottom perimeter barrier, or a portion of a bottom perimeter barrier,underneath a formation. In some embodiments, freeze wells may be used toform a top perimeter barrier, or a portion of a top perimeter barrier,above a formation.

[2267] In some embodiments, freeze wells may be maintained attemperatures significantly colder than a freezing temperature offormation water. Heat may transfer from the formation to the freezewells so that a low temperature zone is formed around the freeze wells.A portion of formation water that is in, or flows into, the lowtemperature zone may freeze to form a barrier to fluid flow. Freezewells may be spaced and operated so that the low temperature zone formedby each freeze well overlaps and connects with a low temperature zoneformed by at least one adjacent freeze well.

[2268] Sections of freeze wells that are able to form low temperaturezones may be only a portion of the overall length of the freeze wells.For example, a portion of each freeze well may be insulated adjacent toan overburden so that heat transfer between the freeze wells and theoverburden is inhibited. The freeze wells may form a low temperaturezone along sides of a hydrocarbon containing portion of the formation.The low temperature zone may extend above and/or below a portion of thehydrocarbon containing layer to be treated by in situ conversion. Theability to use only portions of freeze wells to form a low temperaturezone may allow for economic use of freeze wells when forming barriersfor treatment areas that are relatively deep within the formation.

[2269] A perimeter barrier formed by freeze wells may have severaladvantages over perimeter barriers formed by other methods. A perimeterbarrier formed by freeze wells may be formed deep within the ground. Aperimeter barrier formed by freeze wells may not require aninterconnected opening around the perimeter of a treatment area. Aninterconnected opening is typically needed for grout walls and someother types of perimeter barriers. A perimeter barrier formed by freezewells develops due to heat transfer, not by mass transfer. Gel, polymer,and some other types of perimeter barriers depend on mass transferwithin the formation to form the perimeter barrier. Heat transfer in aformation may vary throughout a formation by a relatively small amount(e.g., typically by less than a factor of 2 within a formation layer).Mass transfer in a formation may vary by a much greater amountthroughout a formation (e.g., by a factor of 10⁸ or more within aformation layer). A perimeter barrier formed by freeze wells may havegreater integrity and be easier to form and maintain than a perimeterbarrier that needs mass transfer to form.

[2270] A perimeter barrier formed by freeze wells may provide a thermalbarrier between different treatment areas and between surroundingportions of the formation that are to remain untreated. The thermalbarrier may allow adjacent treatment areas to be subjected to differentprocesses. The treatment areas may be operated at different pressures,temperatures, heating rates, and/or formation fluid removal rates. Thethermal barrier may inhibit hydrocarbon material on an outer side of thebarrier from being pyrolyzed when the treatment area is heated.

[2271] Forming a frozen perimeter barrier around a treatment area withfreeze wells may be more economical and beneficial over the life of anin situ conversion process than operating dewatering wells around thetreatment area. Freeze wells may be less expensive to install, operate,and maintain than dewatering wells. Casings for dewatering wells mayneed to be formed of corrosion resistant metals to withstand corrosionfrom formation water over the life of an in situ conversion process.Freeze wells may be made of carbon steel. Dewatering wells may enhancethe spread of formation fluid from a treatment area. Water produced fromdewatering wells may contain a portion of formation fluid. Such watermay need to be treated to remove hydrocarbons and other material beforethe water can be released. Dewatering wells may inhibit the ability toraise pressure within a treatment area to a desired value sincedewatering wells are constantly removing fluid from the formation.

[2272] Water presence in a low temperature zone may allow for theformation of a frozen barrier. The frozen barrier may be a monolithic,impermeable structure. After the frozen barrier is established, theenergy requirements needed to maintain the frozen barrier may besignificantly reduced, as compared to the energy costs needed toestablish the frozen barrier. In some embodiments, the reduction in costmay be a factor of 10 or more. In other embodiments, the reduction incost may be less dramatic, such as a reduction by a factor of about 3 or4.

[2273] In many formations, hydrocarbon containing portions of theformation are saturated or contain sufficient amounts of formation waterto allow for formation of a frozen barrier. In some formations, watermay be added to the formation adjacent to freeze wells after and/orduring formation of a low temperature zone so that a frozen barrier willbe formed.

[2274] In some in situ conversion embodiments, a low temperature zonemay be formed around a treatment area. During heating of the treatmentarea, water may be released from the treatment area as steam and/orentrained water in formation fluids. In general, when a treatment areais initially heated, water present in the formation is mobilized beforesubstantial quantities of hydrocarbons are produced. The water may befree water and/or released water that was attached or bound to clays orminerals (“bound water”). Mobilized water may flow into the lowtemperature zone. The water may condense and subsequently solidify inthe low temperature zone to form a frozen barrier.

[2275] Pyrolyzing hydrocarbons and/or oxidizing hydrocarbons may formwater vapor during in situ conversion. A significant portion of thegenerated water vapor may be removed from the formation throughproduction wells. A small portion of the generated water vapor maymigrate towards the perimeter of the treatment area. As the waterapproaches the low temperature zone formed by the freeze wells, aportion of the water may condense to liquid water in the low temperaturezone. If the low temperature zone is cold enough, or if the liquid watermoves into a cold enough portion of the low temperature zone, the watermay solidify.

[2276] In some embodiments, freeze wells may form a low temperature zonethat does not result in solidification of formation fluid. For example,if there is insufficient water or other fluid with a relatively highfreezing point in the formation around the freeze wells, then the freezewells may not form a frozen barrier. Instead, a low temperature zone maybe formed. During an in situ conversion process, formation fluid maymigrate into the low temperature zone. A portion of formation fluid(e.g., low freezing point hydrocarbons) may condense in the lowtemperature zone. The condensed fluid may fill pore space within the lowtemperature zone. The condensed fluid may form a barrier to additionalfluid flow into or out of the low temperature zone. A portion of theformation fluid (e.g., water vapor) may condense and freeze within thelow temperature zone to form a frozen barrier. Condensed formation fluidand/or solidified formation fluid may form a barrier to further fluidflow into or out of the low temperature zone.

[2277] Freeze wells may be initiated a significant time in advance ofinitiation of heat sources that will heat a treatment area. Initiatingfreeze wells in advance of heat source initiation may allow for theformation of a thick interconnected frozen perimeter barrier beforeformation temperature in a treatment area is raised. In someembodiments, heat sources that are located a large distance away from aperimeter of a treatment area may be initiated before, simultaneouslywith, or shortly after initiation of freeze wells.

[2278] Heat sources may not be able to break through a frozen perimeterbarrier during thermal treatment of a treatment area. In someembodiments, a frozen perimeter barrier may continue to expand for asignificant time after heating is initiated. Thermal diffusivity of ahot, dry formation may be significantly smaller than thermal diffusivityof a frozen formation. The difference in thermal diffusivities betweenhot, dry formation and frozen formation implies that a cold zone willexpand at a faster rate than a hot zone. Even if heat sources are placedrelatively close to freeze wells that have formed a frozen barrier(e.g., about 1 m away from freeze wells that have established a frozenbarrier), the heat sources will typically not be able to break throughthe frozen barrier if coolant is supplied to the freeze wells. Incertain ICP system embodiments, freeze wells are positioned asignificant distance away from the heat sources and other ICP wells. Thedistance may be about 3 m, 5 m, 10 m, 15 m, or greater.

[2279] The frozen barrier formed by the freeze wells may expand on anoutward side of the perimeter barrier even when heat sources heat theformation on an inward side of the perimeter barrier.

[2280]FIG. 379 depicts a representation of freeze wells 2756 installedin a formation to form low temperature zones 2762 around treatment areas2750. Fluid in low temperature zones 2762 with a freezing point above atemperature of the low temperature zones may solidify in the lowtemperature zones to form perimeter barrier 2752. Typically, the fluidthat solidifies to form perimeter barrier 2752 will be a portion offormation water. Two or more rows of freeze wells may be installedaround treatment area 2750 to form a thicker low temperature zone 2762than can be formed using a single row of freeze wells. FIG. 387 depictstwo rows of freeze wells 2756 around treatment area 2750. Freeze wells2756 may be placed around all of treatment area 2750, or freeze wellsmay be placed around a portion of the treatment area. In someembodiments, natural fluid flow barriers (such as unfractured,substantially impermeable formation material) and/or artificial barriers(e.g., grout walls or interconnected sheet barriers) surround remainingportions of the treatment area when freeze wells do not surround all ofthe treatment area.

[2281] If more than one row of freeze wells surrounds a treatment area,the wells in a first row may be staggered relative to wells in a secondrow. In the freeze well arrangement embodiment depicted in FIG. 387,first separation distance 2764 exists between freeze wells 2756 in a rowof freeze wells. Second separation distance 2766 exists between freezewells 2756 in a first row and a second row. Second separation distance2766 may be about 10-75% (e.g., 30-60% or 50%) of first separationdistance 2764. Other separation distances and freeze well patterns mayalso be used.

[2282]FIG. 383 depicts an embodiment of an ICP system with freeze wells2756 that form low temperature zone 2762 below a portion of a formation,a low temperature zone above a portion of a formation, and a lowtemperature zone along a perimeter of a portion of the formation.Portions of heat sources 508 and portions of production wells 512 maypass through low temperature zone 2762 formed by freeze wells 2756. Theportions of heat sources 508 and production wells 512 that pass throughlow temperature zone 2762 may be insulated to inhibit heat transfer tothe low temperature zone. The insulation may include, but is not limitedto, foamed cement, an air gap between an insulated liner placed in theproduction well, or a combination thereof.

[2283] A portion of a freeze well that is to form a low temperature zonein a formation may be placed in the formation in desired spaced relationto an adjacent freeze well or freeze wells so that low temperature zonesformed by the individual freeze wells interconnect to form a continuouslow temperature zone. In some freeze well embodiments, each freeze wellmay have two or more sections that allow for heat transfer with anadjacent formation. Other sections of the freeze wells may be insulatedto inhibit heat transfer with the adjacent formation.

[2284] Freeze wells may be placed in the formation so that there isminimal deviation in orientation of one freeze well relative to anadjacent freeze well. Excessive deviation may create a large separationdistance between adjacent freeze wells that may not permit formation ofan interconnected low temperature zone between the adjacent freezewells. Factors that may influence the manner in which freeze wells areinserted into the ground include, but are not limited to, freeze wellinsertion time, depth that the freeze wells are to be inserted,formation properties, desired well orientation, and economics.Relatively low depth freeze wells may be impacted and/or vibrationallyinserted into some formations. Freeze wells may be impacted and/orvibrationally inserted into formations to depths from about 1 m to about100 m without excessive deviation in orientation of freeze wellsrelative to adjacent freeze wells in some types of formations. Freezewells placed deep in a formation or in formations with layers that aredifficult to drill through may be placed in the formation by directionaldrilling and/or geosteering. Directional drilling with steerable motorsuses an inclinometer to guide the drilling assembly. Periodic gyro logsare obtained to correct the path. An example of a directional drillingsystem is VertiTrak™ available from Baker Hughes Inteq (Houston, Tex.).Geosteering uses analysis of geological and survey data from an activelydrilling well to estimate stratigraphic and structural position neededto keep the wellbore advancing in a desired direction. Electrical,magnetic, and/or other signals produced in an adjacent freeze well mayalso be used to guide directionally drilled wells so that a desiredspacing between adjacent wells is maintained. Relatively tight controlof the spacing between freeze wells is an important factor in minimizingthe time for completion of a low temperature zone.

[2285]FIG. 388 depicts a representation of an embodiment of freeze well2756 that is directionally drilled into a formation. Freeze well 2756may enter the formation at a first location and exit the formation at asecond location so that both ends of the freeze well are above theground surface. Refrigerant flow through freeze well 2756 may reduce thetemperature of the formation adjacent to the freeze well to form lowtemperature zone 2762. Refrigerant passing through freeze well 2756 maybe passed through an adjacent freeze well or freeze wells. Temperatureof the refrigerant may be monitored. When the refrigerant temperatureexceeds a desired value, the refrigerant may be directed to arefrigeration unit or units to reduce the temperature of the refrigerantbefore recycling the refrigerant back into the freeze wells. The use offreeze wells that both enter and exit the formation may eliminate theneed to accommodate an inlet refrigerant passage and an outletrefrigerant passage in each freeze well.

[2286] Freeze well 2756 depicted in the embodiment of FIG. 388 formspart of frozen barrier 2768 below water body 2769. Water body 2769 maybe any type of water body such as a pond, lake, stream, or river. Insome embodiments, the water body may be a subsurface water body such asan underground stream or river. Freeze well 2756 is one of many freezewells that may inhibit downward migration of water from water body 2769to hydrocarbon containing layer 522.

[2287]FIG. 389 depicts a representation of freeze wells 2756 used toform a low temperature zone on a side of hydrocarbon containing layer522. In some embodiments, freeze wells 2756 may be placed in anon-hydrocarbon containing layer that is adjacent to hydrocarboncontaining layer 522. In the depicted embodiment, freeze wells 2756 areoriented along dip of hydrocarbon containing layer 522. In someembodiments, freeze wells may be inserted into the formation from twodifferent directions or substantially perpendicular to the groundsurface to limit the length of the freeze wells. Freeze well 2756A andother freeze wells may be inserted into hydrocarbon containing layer 522to form a perimeter barrier that inhibits fluid flow along thehydrocarbon containing layer. If needed, additional freeze wells may beinstalled to form perimeter barriers to inhibit fluid flow into or fromoverburden 524 or underburden 914.

[2288] As depicted in FIG. 382, freeze wells 2756 may be positionedwithin a portion of a formation. Freeze wells 2756 and ICP wells mayextend through overburden 524, through hydrocarbon layer 522, and intounderburden 914. In some embodiments, portions of freeze wells and ICPwells extending through the overburden 524 may be insulated to inhibitheat transfer to or from the surrounding formation.

[2289] In some embodiments, dewatering wells 1978 may extend intoformation 522. Dewatering wells 1978 may be used to remove formationwater from hydrocarbon containing layer 522 after freeze wells 2756 formperimeter barrier 2752. Water may flow through hydrocarbon containinglayer 522 in an existing fracture system and channels. Only a smallnumber of dewatering wells 1978 may be needed to dewater treatment area2750 because the formation may have a large permeability due to theexisting fracture system and channels. Dewatering wells 1978 may beplaced relatively close to freeze wells 2756. In some embodiments,dewatering wells may be temporarily sealed after dewatering. Ifdewatering wells are placed close to freeze wells or to a lowtemperature zone formed by freeze wells, the dewatering wells may befilled with water. Expanding low temperature zone 2762 may freeze thewater placed in the dewatering wells to seal the dewatering wells.Dewatering wells 1978 may be re-opened after completion of in situconversion. After in situ conversion, dewatering wells 1978 may be usedduring clean-up procedures for injection or removal of fluids.

[2290] In some embodiments, selected production wells, heat sources, orother types of ICP wells may be temporarily converted to dewateringwells by attaching pumps to the selected wells. The converted wells maysupplement dewatering wells or eliminate the need for separatedewatering wells. Converting other wells to dewatering wells mayeliminate costs associated with drilling wellbores for dewatering wells.

[2291]FIG. 390 depicts a representation of an embodiment of a wellsystem for treating a formation. Hydrocarbon containing layer 522 mayinclude leached/fractured portion 2771 and non-leached/non-fracturedportion 2770. Formation water may flow through leached/fractured portion2771. Non-leached/non-fractured portion 2770 may be unsaturated andrelatively dry. In some formations, leached/fractured portion 2771 maybe beneath 100 m or more of overburden 524, and the leached/fracturedportion may extend 200 m or more into the formation.Non-leached/non-fractured portion 2770 may extend 400 m or more deeperinto the formation.

[2292] Heat source 508 may extend to underburden 914 belownon-leached/non-fractured portion 2770. Production wells may extend intothe non-leached/non-fractured portion of the formation. The productionwells may have perforations, or be open wellbores, along the portionsextending into the leached/fractured portion andnon-leached/non-fractured portions of the hydrocarbon containing layer.Freeze wells 2756 may extend close to, or a short distance into,non-leached/non-fractured portion 2770. Freeze wells 2756 may be offsetfrom heat sources 508 and production wells a distance sufficient toallow hydrocarbon material below the freeze wells to remain unpyrolyzedduring treatment of the formation (e.g., about 30 m). Freeze wells 2756may inhibit formation water from flowing into hydrocarbon containinglayer 522. Advantageously, freeze wells 2756 do not need to extend alongthe full length of hydrocarbon material that is to be subjected to insitu conversion, because non-leached/non-fractured portion 2770 beneathfreeze wells 2756 may remain untreated. If treatment of the formationgenerates thermal fractures in the non-leached/non-fractured portion2770 that propagate towards and/or past freeze wells 2756, the fracturesmay remain substantially horizontally oriented. Horizontally orientedfractures will not intersect the leached/fractured portion 2771 to allowformation water to enter into treatment area 2750.

[2293] Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: type offreeze well; a distance between adjacent freeze wells; refrigerant; timeframe in which to form a low temperature zone; depth of the lowtemperature zone; temperature differential to which the refrigerant willbe subjected; chemical and physical properties of the refrigerant;environmental concerns related to potential refrigerant releases, leaks,or spills; economics; formation water flow in the formation; compositionand properties of formation water; and various properties of theformation such as thermal conductivity, thermal diffusivity, and heatcapacity.

[2294] Several different types of freeze wells may be used to form a lowtemperature zone. The type of freeze well used may depend on the type ofrefrigeration system used to form a low temperature zone. The type ofrefrigeration system may be, but is not limited to, a batch operatedrefrigeration system, a circulated fluid refrigeration system, arefrigeration system that utilizes a vaporization cycle, a refrigerationsystem that utilizes an adsorption-desorption refrigeration cycle, or arefrigeration system that uses an absorption-desorption refrigerationcycle. Different types of refrigeration systems may be used at differenttimes during formation and/or maintenance of a low temperature zone. Insome embodiments, freeze wells may include casings. In some embodiments,freeze wells may include perforated casings or casings with other typesof openings. In some embodiments, a portion of a freeze well may be anopen wellbore.

[2295] A batch operated refrigeration system may utilize a plurality offreeze wells. A refrigerant is placed in the freeze wells. Heattransfers from the formation to the freeze wells. The refrigerant may bereplenished or replaced to maintain the freeze wells at desiredtemperatures.

[2296]FIG. 391 depicts an embodiment of batch operated freeze well 2756.Freeze well 2756 may include casing 550, inlet conduit 2772, ventconduit 2774, and packing 2776. Packing 2776 may be formed near a top ofwhere a low temperature zone is to be formed in a formation. In someembodiments, packing is not utilized. Inlet conduit 2772 and/or ventconduit 2774 may extend through packing 2776. Refrigerant 2778 may beinserted into freeze well 2756 through inlet conduit 2772. Inlet conduit2772 may be insulated, or formed of an insulating material, to inhibitheat transfer to refrigerant 2778 as the refrigerant is transportedthrough the inlet conduit. In an embodiment, inlet conduit 2772 isformed of high density polyethylene. Vapor generated by heat transferbetween the formation and refrigerant 2778 may exit freeze well 2756through vent conduit 2774. In some embodiments, a vent conduit may notbe needed.

[2297] In some freeze well embodiments, a low temperature zone may beformed by batch operated freeze wells that do not include sealedcasings. Portions of freeze wells may be open wellbores, and/or portionsof the wellbores may include casings that have perforations or othertypes of openings. FIG. 392 depicts an embodiment of freeze well 2756that includes an open wellbore portion. To use freeze wells that includeopen wellbore portions and/or perforations or other types of openings,water may be introduced into the freeze wells to fill fractures and/orpore space within the formation adjacent to the wellbore. A pump may beused to remove excess water from the wellbore. In some embodiments,addition of water into the wellbore may not be necessary. Cryogenicrefrigerant 2778, such as liquid nitrogen, may be introduced into thewellbores to freeze material in the formation adjacent to the wellboresand seal any fractures or pore spaces of the formation that are adjacentto the freeze wells. Cryogenic refrigerant 2778 may be periodicallyreplenished so that a frozen barrier is formed and maintained.Alternately, a less cold, less expensive fluid, (such as a dry ice andlow freezing point liquid bath) may be substituted for the cryogenicrefrigerant after evaporation or removal of the cryogenic refrigerantfrom the wellbores. The less cold fluid may be used to form and/ormaintain the frozen barrier.

[2298] A need to replenish refrigerant may make the use of batchoperated freeze wells economical only for forming a low temperature zonearound a relatively small treatment area. The need to replenishrefrigerant may allow for economical operation of batch operated freezewells only for relatively short periods of time. Batch operated freezewells may advantageously be able to form a frozen barrier in a shortperiod of time, especially if a close freeze well spacing and acryogenic fluid is used. Batch operated freeze wells may be able to forma frozen barrier even when there is a large fluid flow rate adjacent tothe freeze wells. Batch operated freeze wells that use liquid nitrogenmay be able to form a frozen barrier when formation fluid flows at arate of up to about 20 m/day.

[2299] A circulated refrigeration system may utilize a plurality offreeze wells. A refrigerant may be circulated through the freeze wellsand through a refrigeration unit. The refrigeration unit may cool therefrigerant to an initial refrigerant temperature. The freeze wells maybe coupled together in series, parallel, or series and parallelcombinations. The circulated refrigeration system may be a high volumesystem. When the system is initially started, the temperature differencebetween refrigerant entering a refrigeration unit and leaving arefrigeration unit may be relatively large (e.g., from about 10° C. toabout 30° C.) and may quickly diminish. After formation of a frozenbarrier, the temperature difference may be 1 ° C. or less. It may bedesirable for the temperature of the circulated refrigerant to be verylow after the refrigerant passes through a refrigeration unit so thatthe refrigerant will be able to form a thick low temperature zoneadjacent to the freeze wells. An initial working temperature of therefrigerant may be −25° C., −40° C., −50° C., or lower.

[2300]FIG. 393 depicts an embodiment of a circulated refrigerant type ofrefrigeration system that may be used to form low temperature zone 2762around treatment area 2750. The refrigeration system may includerefrigeration units 2780, cold side conduit 2782, warm side conduit2784, and freeze wells 2756. Cold side conduits 2782 and warm sideconduits 2784 (as shown in FIG. 390) may be made of insulated polymerpiping such as HDPE (high-density polyethylene). Cold side conduits 2782and warm side conduits 2784 may couple refrigeration units 2780 tofreeze wells 2756 in series, parallel, or series and parallelarrangements. The type of piping arrangement used to connect freezewells 2756 to refrigeration units 2780 may depend on the type ofrefrigeration system, the number of refrigeration units, and the heatload required to be removed from the formation by the refrigerant.

[2301] In some embodiments, freeze wells 2756 may be connected torefrigeration conduits 2782, 2784 in a parallel configuration asdepicted in FIG. 393. Cold side conduit 2782 may transport refrigerantfrom a first storage tank of refrigeration unit 2780 to freeze wells2756. The refrigerant may travel through freeze wells 2756 to warm sideconduit 2784. Warm side conduit 2784 may transport the refrigerant to asecond storage tank of refrigeration unit 2780. Parallel configurationsfor refrigeration systems may be utilized when a low temperature zoneextends for a long length (e.g., 50 m or longer). Several refrigerationsystems may be needed to form a perimeter barrier around a treatmentarea.

[2302] In some embodiments, freeze wells may be connected torefrigeration conduits in parallel and series configurations. Two ormore freeze wells may be coupled together in a series piping arrangementto form a group. Each group may be coupled in a parallel pipingarrangement to the cold side conduit and the warm side conduit.

[2303] A circulated fluid refrigeration system may utilize a liquidrefrigerant that is circulated through freeze wells. A liquidcirculation system utilizes heat transfer between a circulated liquidand the formation without a significant portion of the refrigerantundergoing a phase change. The liquid may be any type of heat transferfluid able to function at cold temperatures. Some of the desiredproperties for a liquid refrigerant are: a low working temperature, lowviscosity, high specific heat capacity, high thermal conductivity, lowcorrosiveness, and low toxicity. A low working temperature of therefrigerant allows for formation of a large low temperature zone arounda freeze well. A low working temperature of the liquid should be about−20° C. or lower. Fluids having low working temperatures at or below−20° C. may include certain salt solutions (e.g., solutions containingcalcium chloride or lithium chloride). Other salt solutions may includesalts of certain organic acids (e.g., potassium formate, potassiumacetate, potassium citrate, ammonium formate, ammonium acetate, ammoniumcitrate, sodium citrate, sodium formate, sodium acetate). One liquidthat may be used as a refrigerant below −50° C. is Freezium®, availablefrom Kemira Chemicals (Helsinki, Finland). Another liquid refrigerant isa solution of ammonia and water with a weight percent of ammonia betweenabout 20% and about 40%.

[2304] A refrigerant that is capable of being chilled below a freezingtemperature of formation water may be used to form a low temperaturezone. The following equation (the Sanger equation) may be used to modelthe time t₁ needed to form a frozen barrier of radius R around a freezewell having a surface temperature of T_(s): $\begin{matrix}{{t_{1} = {\frac{R^{2}L_{1}}{4k_{f}v_{s}}\left( {{2\ln \frac{R}{r_{o}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} \right)}}{{in}\quad {which}\text{:}}} & (78) \\\begin{matrix}{L_{1} = {L\frac{a_{r}^{2} - 1}{2\ln \quad a_{r}}c_{vu}v_{o}}} \\{a_{r} = {\frac{R_{A}}{R}.}}\end{matrix} & \quad\end{matrix}$

[2305] In these equations, k_(f) is the thermal conductivity of thefrozen material; c_(vf) and c_(vu) are the volumetric heat capacity ofthe frozen and unfrozen material, respectively; r_(o) is the radius ofthe freeze well; v_(s) is the temperature difference between the freezewell surface temperature T_(s) and the freezing point of water T_(o);v_(o) is the temperature difference between the ambient groundtemperature T_(g) and the freezing point of water T_(o); L is thevolumetric latent heat of freezing of the formation; R is the radius atthe frozen-unfrozen interface; and R_(A) is a radius at which there isno influence from the refrigeration pipe. The temperature of therefrigerant is an adjustable variable that may significantly affect thespacing between refrigeration pipes.

[2306]FIG. 394 shows simulation results as a plot of time to reduce atemperature midway between two freeze wells to 0° C. versus well spacingusing refrigerant at an initial temperature of −50° C. and usingrefrigerant at an initial temperature of −25° C. The formation beingcooled in the simulation was 83.3 liters of liquid oil/metric ton GreenRiver oil shale. The results for the −50° C. temperature refrigerant aredenoted by reference numeral 2786. The results for the −25° C.temperature refrigerant are denoted by reference numeral 2788. Thisfigure shows that reducing refrigerant temperature will reduce the timeneeded to form an interconnected low temperature zone sufficiently coldto freeze formation water. For example, reducing the initial refrigeranttemperature from −25° C. to −50° C. may halve the time needed to form aninterconnected low temperature zone for a given spacing between freezewells.

[2307] In certain circumstances (e.g., where hydrocarbon containingportions of a formation are deeper than about 300 m), it may bedesirable to minimize the number of freeze wells (i.e., increase freezewell spacing) to improve project economics. Using a refrigerant that cango to low temperatures allows for the use of a large freeze wellspacing.

[2308] EQN. 78 implies that a large low temperature zone may be formedby using a refrigerant having an initial temperature that is very low.To form a low temperature zone for in situ conversion processes forformations, the use of a refrigerant having an initial cold temperatureof about −50° C. or lower may be desirable. Refrigerants having initialtemperatures warmer than about −50° C. may also be used, but suchrefrigerants may require longer times for the low temperature zonesproduced by individual freeze wells to connect. In addition, suchrefrigerants may require the use of closer freeze well spacings and/ormore freeze wells.

[2309] A refrigeration unit may be used to reduce the temperature of arefrigerant liquid to a low working temperature. In some embodiments,the refrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.),Gartner Refrigeration & Manufacturing (Minneapolis, Minn.), and othersuppliers. In some embodiments, a cascading refrigeration system may beutilized with a first stage of ammonia and a second stage of carbondioxide. The circulating refrigerant through the freeze wells may be 30weight % ammonia in water (aqua ammonia).

[2310] In some embodiments, refrigeration units for chilling refrigerantmay utilize an absorption-desorption cycle. An absorption refrigerationunit may produce temperatures down to about −60° C. using thermalenergy. Thermal energy sources used in the desorption unit of theabsorption refrigeration unit may include, but are not limited to, hotwater, steam, formation fluid, and/or exhaust gas. In some embodiments,ammonia is used as the refrigerant and water as the absorbent in theabsorption refrigeration unit. Absorption refrigeration units areavailable from Stork Thermeq B.V. (Hengelo, The Netherlands).

[2311] A vaporization cycle refrigeration system may be used to formand/or maintain a low temperature zone. A liquid refrigerant may beintroduced into a plurality of wells. The refrigerant may absorb heatfrom the formation and vaporize. The vaporized refrigerant may becirculated to a refrigeration unit that compresses the refrigerant to aliquid and reintroduces the refrigerant into the freeze wells. Therefrigerant may be, but is not limited to, ammonia, carbon dioxide, or alow molecular weight hydrocarbon (e.g., propane). After vaporization,the fluid may be recompressed to a liquid in a refrigeration unit orrefrigeration units and circulated back into the freeze wells. The useof a circulated refrigerant system may allow economical formation and/ormaintenance of a long low temperature zone that surrounds a largetreatment area. The use of a vaporization cycle refrigeration system mayrequire a high pressure piping system.

[2312]FIG. 395 depicts an embodiment of freeze well 2756. Freeze well2756 may include casing 550, inlet conduit 2772, spacers 2790, andwellcap 2792. Spacers 2790 may position inlet conduit 2772 within casing550 so that an annular space is formed between the casing and theconduit. Spacers 2790 may promote turbulent flow of refrigerant in theannular space between inlet conduit 2772 and casing 550, but the spacersmay also cause a significant fluid pressure drop. Turbulent fluid flowin the annular space may be promoted by roughening the inner surface ofcasing 550, by roughening the outer surface of inlet conduit 2772,and/or by having a small cross-sectional area annular space that allowsfor high refrigerant velocity in the annular space. In some embodiments,spacers are not used.

[2313] Refrigerant may flow through cold side conduit 2782 from arefrigeration unit to inlet conduit 2772 of freeze well 2756. Therefrigerant may flow through an annular space between inlet conduit 2772and casing 550 to warm side conduit 2784. Heat may transfer from theformation to casing 550 and from the casing to the refrigerant in theannular space. Inlet conduit 2772 may be insulated to inhibit heattransfer to the refrigerant during passage of the refrigerant intofreeze well 2756. In an embodiment, inlet conduit 2772 is a high densitypolyethylene tube. In other embodiments, inlet conduit 2772 is aninsulated metal tube.

[2314]FIG. 396 depicts an embodiment of circulated refrigerant freezewell 2756. Refrigerant may flow through U-shaped conduit 2794 that issuspended or packed in casing 550. Suspending conduit 2794 in casing 550may advantageously provide thermal contraction and expansion room forthe conduit. In some embodiments, spacers may be positioned at selectedlocations along the length of the conduit to inhibit conduit 2794 fromcontacting casing 550. Typically, preventing conduit 2794 fromcontacting casing 550 is not needed, so spacers are not used. Casing 550may be filled with a low freezing point heat transfer fluid to enhancethermal contact and promote heat transfer between the formation, casing,and conduit 2794. In some embodiments, water or other fluid that willsolidify when refrigerant flows through conduit 2794 may be placed incasing 550. The solid formed in casing 550 may enhance heat transferbetween the formation, casing, and refrigerant within conduit 2794.Portions of conduit 2794 adjacent to the formation that are not to becooled may be formed of an insulating material (e.g., high densitypolyethylene) and/or the conduit portions may be insulated. Portions ofconduit 2794 adjacent to the formation that are to be cooled may beformed of a thermally conductive metal (e.g., copper or a copper alloy)to enhance heat transfer between the formation and refrigerant withinthe conduit portion.

[2315] In some freeze well embodiments, U-shaped conduits may besuspended or packed in open wellbores or in perforated casings insteadof in sealed casings. FIG. 397 depicts an embodiment of freeze well 2756having an open wellbore portion. Open wellbores and/or perforatedcasings may be used when water or other fluid is to be introduced intothe formation from the freeze wells. Water may be introduced into theformation to promote formation of a frozen barrier. Water may beintroduced into the formation through freeze wells during cleanupprocedures after completion of an in situ conversion process (e.g., thefreeze wells may be thawed and perforated for introduction of water). Insome embodiments, open wellbores and/or perforated casings may be usedwhen the freeze wells will later be converted to heat sources,production wells, and/or injection wells.

[2316] As depicted in FIG. 397, outlet leg 2796 of U-shaped conduit 2794may be wrapped around inlet leg 2798 adjacent to a portion of theformation that is to be cooled. Wrapping outlet leg 2796 around inletleg 2798 may significantly increase the heat transfer surface area ofconduit 2794. Inlet leg and outlet leg adjacent to portions of theformation that are not to be cooled may be insulated and/or made of aninsulating material. Conduits with an outlet leg wrapped around an inletleg are available from Packless Hose, Inc. (Waco, Tex.).

[2317] A time needed to form a low temperature zone may be dependent ona number of factors and variables. Such factors and variables mayinclude, but are not limited to, freeze well spacing, refrigeranttemperature, length of the low temperature zone, fluid flow rate intothe treatment area, salinity of the fluid flowing into the treatmentarea, and the refrigeration system type, or refrigerant used to form thebarrier. The time needed to form the low temperature zone may range fromabout two days to more than a year depending on the extent and spacingof the freeze wells. In some embodiments, a time needed to form a lowtemperature zone may be about 6 to 8 months.

[2318] Spacing between adjacent freeze wells may be a function of anumber of different factors. The factors may include, but are notlimited to, physical properties of formation material, type ofrefrigeration system, type of refrigerant, flow rate of material into orout of a treatment area defined by the freeze wells, time for formingthe low temperature zone, and economic considerations. Consolidated orpartially consolidated formation material may allow for a largeseparation distance between freeze wells. A separation distance betweenfreeze wells in consolidated or partially consolidated formationmaterial may be from about 3 m to 10 m or larger. In an embodiment, thespacing between adjacent freeze wells is about 5 m. Spacing betweenfreeze wells in unconsolidated or substantially unconsolidated formationmaterial may need to be smaller than spacing in consolidated formationmaterial. A separation distance between freeze wells in unconsolidatedmaterial may be 1 m or more.

[2319] Numerical simulations may be used to determine spacing for freezewells based on known physical properties of the formation. A generalpurpose simulator, such as the Steam, Thermal and Advanced ProcessesReservoir Simulator (STARS), may be used for numerical simulation work.Also, a simulator for freeze wells, such as TEMP W available fromGeoslope (Calgary, Alberta), may be used for numerical simulations. Thenumerical simulations may include the effect of heat sources operatingwithin a treatment area defined by the freeze wells.

[2320] A time needed to form a frozen barrier may be determined bycompleting a thermal analysis using a finite element model. FIG. 398depicts results of a simulation using TEMP W for 83.3 liters of liquidoil/metric ton of Green River oil shale presented as temperature versustime for a formation cooled with a refrigerant that has an initialworking temperature of −50° C. Curve 2800 depicts a representation of atemperature of an outer wall of a freeze well casing. Curve 2802 depictsa temperature midway between two freeze wells that are separated byabout 7.6 m. Curve 2804 depicts temperature midway between two freezewells that are separated by about 6.1 m. Curve 2806 depicts temperaturemidway between two freeze wells that are separated by about 4.6 m.

[2321]FIG. 398 illustrates that closer freeze well spacing decreases anamount of time required to form an interconnected low temperature zonecapable of freezing formation water. The freeze well casing temperaturedecreased from about 14° C. to less than −40° C. in less than 200 days.In the same time frame, a temperature at a midpoint between two freezewells with a 4.6 m spacing decreased from about 14° C. to −5° C. As thespacing between the freeze wells increased, the time needed to reduce atemperature at a midpoint between two freeze wells also increased. Theplot indicates that shorter distances between adjacent freeze wells maydecrease the time necessary to form an interconnected low temperaturezone. The freeze wells in the simulation are similar to the freeze wellsdepicted in FIG. 395.

[2322] The use of a specific type of refrigerant may be made based on anumber of different factors. Such factors may include, but are notlimited to, the type of refrigeration system employed, the chemicalproperties of the refrigerant, and the physical properties of therefrigerant.

[2323] Refrigerants may have different equipment requirements. Forexample, cryogenic refrigerants (e.g., liquid nitrogen) may inducegreater temperature differentials than a brine solution. A required flowrate for a circulated cryogenic refrigerant system may be substantiallylower than a required flow rate for a brine solution refrigerant toachieve a desired temperature in a formation. A required volume ofcryogenic refrigerant for a batch refrigeration system may be large. Theuse of a cryogenic refrigerant may result in significant equipmentsavings, but the cost of reducing refrigerant to cryogenic temperaturesmay make the use of a cryogenic refrigeration system uneconomical.

[2324] Fluid flow into a treatment area may inhibit formation of afrozen barrier. Formations having high permeability may have high fluidflow rates that inhibit formation of a frozen barrier. Fluid flow ratemay limit a residence time of a fluid in a low temperature zone around afreeze well. If fluid is flowing rapidly adjacent to a freeze well, aresidence time of the fluid proximate the freeze well may beinsufficient to allow the fluid to freeze in a cylindrical patternaround the freeze well. Fluid flow rate may influence the shape of abarrier formed around freeze wells. A high flow rate may result inirregular low temperature zones around freeze wells. FIG. 399 depictsshapes of low temperature zones 2762 around freeze wells 2756 whenformation water flows by the freeze wells at a rate that allows forformation of frozen barrier 2768. Direction of formation water flow isindicated by arrows 2808. As time passes, the frozen barrier may expandoutwards from the freeze wells. If the formation water flow rate is highenough, the fluid may inhibit overlap of low temperature zones 2762between adjacent wells, as depicted in FIG. 400. In such a situation,formation fluid would continue to flow into a treatment area andformation of a frozen barrier would be inhibited. To alleviate theproblem of non-closure of the low temperature zone, additional freezewells may be installed between the existing freeze wells, dewateringwells may be used to reduce formation fluid flow rate by the freezewells to allow for formation of an interconnected low temperature zone,or other techniques may be used to reduce formation fluid flow to a ratethat will allow low temperature zones from adjacent wells tointerconnect so that a frozen barrier forms.

[2325] In some embodiments, fluid flow into a treatment area may beinhibited to allow formation of a frozen barrier by freeze wells. In anembodiment, dewatering wells may be placed in the formation to inhibitfluid flow past freeze wells during formation of a frozen barrier. Thedewatering wells may be placed far enough away from the freeze wells sothat the dewatering wells do not create a flow rate past the freezewells that inhibits formation of a frozen barrier. In some embodiments,injection wells may be used to inject fluid into the formation so thatfluid flow by the freeze wells is reduced to a level that will allow forformation of interconnected frozen barriers between adjacent freezewells.

[2326] In an embodiment, freeze wells may be positioned between an innerrow and an outer row of dewatering wells. The inner row of dewateringwells and the outer row of dewatering wells may be operated to have aminimal pressure differential so that fluid flow between the inner rowof dewatering wells and the outer row of dewatering wells is minimized.The dewatering wells may remove formation water between the outerdewatering row and the inner dewatering row. The freeze wells may beinitialized after removal of formation water by the dewatering wells.The freeze wells may cool the formation between the inner row and theouter row to form a low temperature zone. The power supplied to thedewatering wells may be reduced stepwise after the freeze wells form aninterconnected low temperature zone that is able to solidify formationwater. Reduction of power to the dewatering wells may allow some waterto enter the low temperature zone. The water may freeze to form a frozenbarrier. Operation of the dewatering wells may be ended when the frozenbarrier is fully formed.

[2327] In some formations, a combination batch refrigeration system andcirculated fluid refrigeration system may be used to form a frozenbarrier when fluid flow into the formation is too high to allowformation of the frozen barrier using only the circulated refrigerationsystem. Batch freeze wells may be placed in the formation and operatedwith cryogenic refrigerant to form an initial frozen barrier thatinhibits or stops fluid flow towards freeze wells of a circulated fluidrefrigeration system. Circulation freeze wells may be placed on a sideof the batch freeze wells towards a treatment area. The batch freezewells may be operated to form a perimeter barrier that stops or reducesfluid flow to the circulation freeze wells. The circulation freeze wellsmay be operated to form a primary perimeter barrier. After formation ofthe primary frozen barrier, use of the batch freeze wells may bediscontinued. Alternately, some or all of the batch operated freezewells may be converted to circulation freeze wells that maintain and/orexpand the initial barrier formed by the batch freeze wells. Convertingsome or all of the batch freeze wells to circulation freeze wells mayallow a thick frozen barrier to be formed and maintained around atreatment area. In some embodiments, a combination of dewatering wellsand batch operated freeze wells may be used to reduce fluid flow pastcirculation freeze wells so that the circulation freeze wells form afrozen barrier.

[2328] Open wellbore freeze wells may be utilized in some formationsthat have very low permeability. Freeze well wellbores may be formed insuch formations. A frozen barrier may initially be formed using a verycold fluid, such as liquid nitrogen, that is placed in casings of thefreeze wells. After the very cold fluid forms an interconnected frozenbarrier around the treatment area, the very cold cryogenic fluid may bereplaced with a circulated refrigerant that will maintain the frozenbarrier during in situ processing of the formation. For example, liquidnitrogen at a temperature of about −196° C. may be used to form aninterconnected frozen barrier around a treatment area by placing theliquid nitrogen within the freeze wells and replenishing the liquidnitrogen when necessary. The liquid nitrogen may be placed in an annularspace between an inlet line and a casing in each freeze well. After theliquid nitrogen forms an interconnected frozen barrier between adjacentfreeze wells, the liquid nitrogen may be removed from the freeze wells.A fluid, such as a low freezing point alcohol, may be circulated intoand out of the freeze wells to raise the temperature adjacent to thefreeze wells. When the temperature of the well casing is sufficientlyhigh to inhibit refrigerant, such as a brine solution, from solidifyingin the freeze wells, the fluid may be replaced with the refrigerant. Therefrigerant may be used to maintain the frozen barrier.

[2329]FIG. 379 depicts freeze wells 2756 installed around treatmentareas 2750. ICP wells 2754 may be installed in treatment areas 2750prior to, simultaneously with, or after insertion of freeze wells 2756.In some embodiments, wellbores for ICP wells 2754 and/or freeze wells2756 may be drilled into a formation. In other embodiments, wellboresmay be formed when the wells are vibrationally inserted and/or driveninto the formation. In some embodiments, well casings are formed of pipesegments. Connections between lengths of pipe may be self-sealingtapered threaded connections, and/or welded joints. In otherembodiments, well casings may be inserted using coiled tubinginstallation. Integrity of coiled tubing may be tested beforeinstallation by hydrotesting at pressure.

[2330] Coiled tubing installation may reduce a number of welded and/orthreaded connections in a length of casing. Welds and/or threadedconnections in coiled tubing may be pre-tested for integrity (e.g., byhydraulic pressure testing). Coiled tubing may be installed more easilyand faster than installation of pipe segments joined together bythreaded and/or welded connections.

[2331] Embodiments of heat sources, production wells, and/or freezewells may be installed in a formation using coiled tubing installation.Some embodiments of heat sources, production wells, and freeze wellsinclude an element placed within an outer casing. For example, aconductor-in-conduit heater may include an outer casing with a conduitdisposed in the casing. A production well may include a heater elementor heater elements disposed within a casing. A freeze well may include arefrigerant inlet conduit disposed within a casing, or a U-shapedconduit disposed in a casing. Spacers may be spaced along a length of anelement, or elements, positioned within a casing to inhibit the element,or elements, from contacting the casing walls.

[2332] In some embodiments of heat sources, production wells, and freezewells, casings may be installed using coiled tube installation. Elementsmay be placed within the casing after the casing is placed in theformation for heat sources or wells that include elements within thecasings. In some embodiments, sections of casings may be threaded and/orwelded and inserted into a wellbore using a drilling rig. In someembodiments, elements may be placed within the casing before the casingis wound onto a reel. The elements within a casing are installed in aformation when the casing is installed in the formation. For example, acoiled tubing reel for forming a freeze well such as the freeze welldepicted in FIG. 395 may include 8.9 cm (3.5 in.) outer diameter carbonsteel coiled tubing with 5.1 cm (2 in.) outer diameter high densitypolyethylene tubing positioned inside the carbon steel tubing. Duringinstallation, a portion of the polyethylene tubing may be cut so thatthe polyethylene tubing will be recessed within the steel casing. Awellcap may be threaded and/or welded to the steel tubing to seal theend of the tubing. The coiled tubing may be inserted by a coiled tubingunit into the formation.

[2333] Care may be taken during design and installation of freeze wellcasing strings to allow for thermal contraction of the casing stringwhen refrigerant passes through the casing. Allowance for thermalcontraction may inhibit the development of stress fractures and leaks inthe casing. If a freeze well casing were to leak, leaking refrigerantmay inhibit formation of a frozen barrier or degrade an existing frozenbarrier. Water or other diluent may be used to flush the formation todiffuse released refrigerant if a leak occurs.

[2334] Diameters of freeze well casings installed in a formation may beoversized as compared to a minimum diameter needed to allow forformation of a low temperature zone. For example, if design calculationsindicate that 10.2 cm (4 in.) piping is needed to provide sufficientheat transfer area between the formation and the freeze wells, 15.2 cm(6 in.) piping may be placed in the formation. The oversized casing mayallow a sleeve or other type of seal to be placed into the casing shoulda leak develop in the freeze well casing.

[2335] In some embodiments, flow meters may be used to monitor for leaksof refrigerant within freeze wells. A first flow meter may measure anamount of refrigerant flow into a freeze well or a group of wells. Asecond flow meter may measure an amount of flow out of a freeze well ora group of freeze wells. A significant difference between themeasurements taken by the first flow meter and the second flow meter mayindicate a leak in the freeze well or in a freeze well of the group offreeze wells. A significant difference between the measurements mayresult in the activation of a solenoid valve that inhibits refrigerantflow to the freeze well or group of freeze wells.

[2336] Freeze well placement may vary depending on a number of factors.The factors may include, but are not limited to, predominant directionof fluid flow within the formation; type of refrigeration system used;spacing of freeze wells; and characteristics of the formation such asdepth, length, thickness, and dip. Placement of freeze wells may alsovary across a formation to account for variations in geological strata.In some embodiments, freeze wells may be inserted into hydrocarboncontaining portions of a formation. In some embodiments, freeze wellsmay be placed near hydrocarbon containing portions of a formation. Insome embodiments, some freeze wells may be positioned in hydrocarboncontaining portions while other freeze wells are placed proximate thehydrocarbon containing portions. Placement of heat sources, dewateringwells, and/or production wells may also vary depending on the factorsaffecting freeze well placement.

[2337] ICP wells may be placed a large distance away from freeze wellsused to form a low temperature zone around a treatment area. In someembodiments, ICP wells may be positioned far enough away from freezewells so that a temperature of a portion of formation between the freezewells and the ICP wells is not influenced by the freeze wells or the ICPwells when the freeze wells have formed an interconnected frozen barrierand ICP wells have raised temperatures throughout a treatment area topyrolysis temperatures. In some embodiments, ICP wells may be placed 20m, 30 m, or farther away from freeze wells used to form a lowtemperature zone.

[2338] In some embodiments, ICP wells may be placed in a relativelyclose proximity to freeze wells. During in situ conversion, a hot zoneestablished by heat sources and a cold zone established by freeze wellsmay reach an equilibrium condition where the hot zone and the cold zonedo not expand towards each other. FIG. 401 depicts thermal simulationresults after 1000 days when heat source 508 at about 650° C. is placedat a center of a ring of freeze wells 2756 that are about 9.1 m awayfrom the heat source and spaced at about 2.4 m intervals. The freezewells are able to maintain frozen barrier 2768 that extends over 1 minwards towards the heat source. On an outer side of the freeze wells,the freeze barrier is much thicker, and the freeze wells influenceportions (e.g., low temperature zone 2762) of the formation up to about15 m away from the freeze wells.

[2339] Thermal diffusivities and other properties of both saturatedfrozen formation material and hot, dry formation material may allowoperation of heat sources close to freeze wells. These properties mayinhibit the heat provided by the heat sources from breaking through afrozen barrier established by the freeze wells. Frozen saturatedformation material may have a significantly higher thermal diffusivitythan hot, dry formation material. The difference in the thermaldiffusivity of hot, dry formation material and cold, saturated formationmaterial predicts that a cold zone will propagate faster than a hotzone. Fast propagation of a cold zone established and maintained byfreeze wells may inhibit a hot zone formed by heat sources from meltingthrough the cold zone during thermal treatment of a treatment area.

[2340] In some embodiments, a heat source may be placed relatively closeto a frozen barrier formed and maintained by freeze wells without theheat source being able to break through the frozen barrier. Although aheat source may be placed close to a frozen barrier, heat sources aretypically placed 5 m or farther away from a frozen barrier formed andmaintained by freeze wells. In an embodiment, heat sources are placedabout 30 m away from freeze wells. Since the heat sources may be placedrelatively close to the frozen barrier, a relatively large section of aformation may be treated without an excessive number of freeze wells. Anumber of freeze wells needed to surround an area increases at asignificantly lower rate than the number of ICP wells needed tothermally treat the surrounded area as the size of the surrounded areaincreases. This is because the surface-to-volume ratio decreases withthe radius of a treated volume.

[2341] Measurable properties and/or testing procedures may indicateformation of a frozen barrier. For example, if dewatering is takingplace on an inner side of freeze wells, the amount of water removed fromthe formation through dewatering wells may significantly decrease as afrozen barrier forms and blocks recharge of water into a treatment area.

[2342] A treatment area may be saturated with formation water. When afrozen perimeter barrier is formed around the treatment area, waterrecharge and removal from the treatment area is stopped. The frozenperimeter barrier may continue to expand. Expansion of the perimeterbarrier may cause the hydrostatic head (i.e., piezometric head) in thetreatment area to rise as compared to the hydrostatic head of formationoutside of the frozen barrier. The hydrostatic head in the barrier mayrise because the water in the formation is confined in an increasinglysmaller volume as the frozen barrier expands inwards. The hydrostaticchange may be relatively small, but still measurable. Piezometers placedinside and outside of a ring of freeze wells may be used to determinewhen a frozen barrier is formed based on hydrostatic head measurements.

[2343] In addition, transient pressure testing (e.g., drawdown tests orinjection tests) in the treatment area may indicate formation of afrozen barrier. Such transient pressure tests may also indicate thepermeability at the barrier. Pressure testing is described in PressureBuildup and Flow Tests in Wells by C. S. Matthews & D. G. Russell (SPEMonograph, 1967).

[2344] A transient fluid pulse test may be used to determine or confirmformation of a perimeter barrier. A treatment area may be saturated withformation water after formation of a perimeter barrier. A pulse may beinstigated inside a treatment area surrounded by the perimeter barrier.The pulse may be a pressure pulse that is produced by pumping fluid(e.g., water) into or out of a wellbore. In some embodiments, thepressure pulse may be applied in incremental steps, and responses may bemonitored after each step. After the pressure pulse is applied, thetransient response to the pulse may be measured by, for example,measuring pressures at monitor wells and/or in the well in which thepressure pulse was applied. Monitoring wells used to detect pressurepulses may be located outside and/or inside of the treatment area.

[2345] In some embodiments, a pressure pulse may be applied by drawing avacuum on the formation through a wellbore. If a frozen barrier isformed, a portion of the pulse will be reflected by the frozen barrierback towards the source of the pulse. Sensors may be used to measureresponse to the pulse. In some embodiments, a pulse or pulses areinstigated before freeze wells are initialized. Response to the pulsesis measured to provide a base line for future responses. After formationof a perimeter barrier, a pressure pulse initiated inside of theperimeter barrier should not be detected by monitor wells outside of theperimeter barrier. Reflections of the pressure pulse measured within thetreatment area may be analyzed to provide information on theestablishment, thickness, depth, and other characteristics of the frozenbarrier.

[2346] In certain embodiments, hydrostatic pressures will tend to changedue to natural forces (e.g., tides, water recharge, etc.). A sensitivepiezometer (e.g., a quartz crystal sensor) may be able to accuratelymonitor natural hydrostatic pressure changes. Fluctuations in naturalhydrostatic pressure changes may indicate formation of a frozen barrieraround a treatment area. For example, if areas surrounding the treatmentarea undergo natural hydrostatic pressure changes but the area enclosedby the frozen barrier does not, this is an indication of formation ofthe frozen barrier.

[2347] In some embodiments, a tracer test may be used to determine orconfirm formation of a frozen barrier. A tracer fluid may be injected ona first side of a perimeter barrier. Monitor wells on a second side ofthe perimeter barrier may be operated to detect the tracer fluid. Nodetection of the tracer fluid by the monitor wells may indicate that theperimeter barrier is formed. The tracer fluid may be, but is not limitedto, carbon dioxide, argon, nitrogen, and isotope labeled water orcombinations thereof. A gas tracer test may have limited use insaturated formations because the tracer fluid may not be able to traveleasily from an injection well to a monitor well through a saturatedformation. In a water saturated formation, an isotope labeled water(e.g., deuterated or tritiated water) or a specific ion dissolved inwater (e.g., thiocyanate ion) may be used as a tracer fluid.

[2348] If tests indicate that a frozen perimeter barrier has not beenformed by the freeze wells, the location of incomplete sections of theperimeter barrier may be determined. Pulse tests may indicate thelocation of unformed portions of a perimeter barrier. Tracer tests mayindicate the general direction in which there is an incomplete sectionof perimeter barrier.

[2349] Temperatures of freeze wells may be monitored to determine thelocation of an incomplete portion of a perimeter barrier around atreatment area. In some freeze well embodiments, such as in theembodiment depicted in FIG. 395 and FIG. 390, freeze well 2756 mayinclude port 2810. Temperature probes, such as resistance temperaturedevices, may be inserted into port 2810. Refrigerant flow to the freezewells may be stopped. Dewatering wells may be operated to draw fluidpast the perimeter barrier. The temperature probes may be moved withinports 2810 to monitor temperature changes along lengths of the freezewells. The temperature may rise quickly adjacent to areas where a frozenbarrier has not formed. After the location of the portion of perimeterbarrier that is unformed is located, refrigerant flow through freezewells adjacent to the area may be increased and/or an additional freezewell may be installed near the area to allow for completion of a frozenbarrier around the treatment area.

[2350] A typical hydrocarbon containing formation treated by a thermaltreatment process may have a thick overburden. Average thickness of anoverburden may be greater than about 20 m, 50 m, or 500 m. Theoverburden may provide a substantially impermeable barrier that inhibitsvapor release to the atmosphere. ICP wells passing into the formationmay include well completions that cement or otherwise seal well casingsfrom surrounding formation material so that formation fluid cannot passto the atmosphere adjacent to the wells.

[2351] In some embodiments of an in situ conversion process, heatsources may be placed in a hydrocarbon containing portion of theformation such that the heat sources do not heat sections of thehydrocarbon containing portion nearest to the ground surface topyrolysis temperatures. The heat sources may heat a section of thehydrocarbon containing portion that is below the untreated section topyrolysis temperatures. The untreated section of hydrocarbon containingmaterial may be considered to be part of the overburden.

[2352] Some formations may have relatively thin overburdens over aportion of the formation. Some formations may have an outcrop thatapproaches or extends to ground surface. In some formations, anoverburden may have fractures or develop fractures during thermalprocessing that connect or approach the ground surface. Some formationsmay have permeable portions that allow formation fluid to escape to theatmosphere when the formation is heated. A ground cover may be providedfor a portion of a formation that will allow, or potentially allow,formation fluid to escape to the atmosphere during thermal processing.

[2353] A ground cover may include several layers. FIG. 402 depicts anembodiment of ground cover 2812. Ground cover 2812 may include fillmaterial 2814 used to level a surface on which the ground cover isplaced, first impermeable layer 2816, insulation 2818, framework 2820,and second impermeable layer 2822. Other embodiments of ground coversmay include a different number of layers. For example, a ground covermay only include a first impermeable layer. In some embodiments, firstimpermeable layer 2816 may be formed of concrete, metal, plastic, clay,or other types of material that inhibit formation fluid from passingfrom the ground to the atmosphere.

[2354] Ground cover 2812 may be sealed to the ground, to ICP wells, tofreeze wells, and to other equipment that passes through the groundcover. Ground cover 2812 may inhibit release of formation fluid to theatmosphere. Ground cover 2812 may also inhibit rain and run-off waterseepage into a treatment area from the ground surface. The choice ofground cover material may be based on temperatures and chemicals towhich ground cover 2812 is subjected. In embodiments in which overburden524 is sufficiently thick so that temperatures at the ground surface arenot influenced, or are only slightly elevated, by heating of theformation, ground cover 2812 may be a polymer sheet. For thinneroverburdens 524, where heating the formation may significantly influencethe temperature at ground surface, ground cover 2812 may be formed ofmetal sheet placed over the treatment area. Ground cover 2812 may beplaced on a graded surface, and wellbores for ICP wells and freeze wellsmay be placed into the formation through the ground cover. Ground cover2812 may be welded or otherwise sealed to well casings and/or otherstructures extending through the ground cover. If needed, insulation2818 may be placed above or below ground cover 2812 to inhibit heat lossto the atmosphere.

[2355] Ground cover 2812 may include framework 2820. In certainembodiments, framework 2820 supports a portion of ground cover 2812. Forexample, framework 2820 may support second impermeable layer 2822, whichmay be a rain cover that extends over a portion or all of the treatmentarea. In other embodiments, framework 2820 supports well casings,walkways, and/or other structures that provide access to wells withinthe treatment area, so that personnel do not have to contact groundcover 2812 when accessing a well or equipment within the treatment area.

[2356] Perforated piping of a piping system may be placed in the groundor adjacent to the ground surface below a ground cover. The perforatedpiping may provide a path for transporting formation fluid passingthrough the formation towards the surface to treatment facilities. Inother embodiments, a piping system may be connected to openings thatpass through the ground cover. Blowers or other types of drive systemsmay draw formation fluid adjacent to the ground cover into the piping.Monitor wells may be placed through a ground cover at the groundsurface. If the monitor wells detect formation fluid, the drive systemmay be activated to transport the fluid to a treatment facility.

[2357] Ground cover 2812 may be sealed to the ground. In an embodimentof an in situ conversion process, freeze wells 2756 are used to form alow temperature zone around the treatment area. A portion of therefrigerant capacity utilized in freeze wells 2756 may be used to freezea portion of the formation adjacent to the ground surface. Ground cover2812 may include a lip that is pushed into wet ground prior to formationof the low temperature zone. When the low temperature zone is formed,the freeze wells may freeze the ground and the ground cover together.Insulation may be placed over the frozen ground to inhibit heatabsorption from the atmosphere. In other embodiments, a ground cover maybe welded or otherwise sealed to a sheet barrier or a grout wall formedin the formation around the treatment area.

[2358] In some embodiments, an upper layer of a formation (e.g., anoutcrop) that allows, or potentially allows, formation fluid to escapeto the atmosphere during thermal treatment is excavated. The depth ofthe excavation opening created may be about ⅓ m, 1 m, 5 m, 10 m, orgreater. Perforated piping of a piping system may be placed in theexcavation and covered with a permeable layer such as sand and/orgravel. A concrete, clay, or other impermeable layer may be formed as acover over the excavation opening. Alternately, a similar structure maybe built on top of the ground to form an impermeable cover over aportion of a formation. The concrete, clay, or other impermeable layermay function as an artificial overburden.

[2359] A treatment area may be subjected to various processessequentially. Treatment areas may undergo many different processesincluding, but not limited to, initial heating, production ofhydrocarbons, pyrolysis, synthesis gas generation, storage of fluids,sequestration, remediation, use as a filtration unit, solution mining,and/or upgrading of hydrocarbon containing feed streams. Fluids may bestored in a formation as long term storage and/or as temporary storageduring unusual situations such as a power failure or treatmentfacilities shutdown. Various factors may be used to determine whichprocesses will be used in particular treatment areas. Factorsdetermining the use of a formation may include, but are not limited to,formation characteristics such as type, size, hydrology, and location;economic viability of a process; available market for products producedfrom the formation; available treatment facilities to process fluidremoved from the formation; and/or feedstocks for introduction into aformation to produce desired products.

[2360] For some processes, a low temperature zone may be used to isolatea treatment area. A treatment area surrounded by a low temperature zonemay be used, in certain embodiments, as a storage area for fluidsproduced or needed on site. Fluids may be diverted from other areas ofthe formation in the event of an emergency. Alternatively, fluids may bestored in a treatment area for later use. A low temperature zone mayinhibit flow of stored fluids from a treatment area depending oncharacteristics of the stored fluids. A frozen barrier zone may benecessary to inhibit flow of certain stored fluids from a treatmentarea. Other processes which may benefit from an isolated treatment zonemay include, but are not limited to, synthesis gas generation, upgradingof hydrocarbon containing feed streams, filtration of feed stocks,and/or solution mining.

[2361] In some in situ conversion process embodiments, three or moresets of wells may surround a treatment area. FIG. 404B depicts a wellpattern embodiment for an in situ conversion process. Treatment area2750 may include a plurality of heat sources, production wells, and/orother types of ICP wells 2754. Treatment area 2750 may be surrounded bya first set of freeze wells 2756. The first set of freeze wells 2756 mayestablish a frozen barrier that inhibits migration of fluid out oftreatment area 2750 during the in situ conversion process.

[2362] The first set of freeze wells 2756 may be surrounded by a set ofmonitor and/or injection wells 606. Monitor and/or injection wells 606may be used during the in situ conversion process to monitor temperatureand monitor for the presence of formation fluid (e.g., for water, steam,hydrocarbons, etc.). If hydrocarbons or steam are detected, a breach ofthe frozen barrier established by the first set of freeze wells 2756 maybe indicated. Measures may be taken to determine the location of thebreach in the frozen barrier. After determining the location of thebreach, measures may be taken to stop the breach. In an embodiment, anadditional freeze well or freeze wells may be inserted into theformation between the first set of freeze wells and the set of monitorand/or injection wells 606 to seal the breach.

[2363] The set of monitor and/or injection wells 606 may be surroundedby a second set of freeze wells 2756A. The second set of freeze wells2756A may form a frozen barrier that inhibits migration of fluid (e.g.,water) from outside the second set of freeze wells into treatment area2750. The second set of freeze wells 2756A may also form a barrier thatinhibits migration of fluid past the second set of freeze wells shouldthe frozen barrier formed by the first set of freeze wells 2756 developa breach. A frozen barrier formed by the second set of freeze wells2756A may stop migration of formation fluid and allow sufficient timefor the breach in the frozen barrier formed by the first set of freezewells 2756 to be fixed. Should a breach form in the frozen barrierformed by the first set of freeze wells 2756, the frozen barrier formedby the second set of freeze wells 2756A may limit the area thatformation fluid from the treatment area can flow into, and thus the areathat needs to be cleaned after the in situ conversion process iscomplete.

[2364] If the set of monitor and/or injection wells 606 detect thepresence of formation water, a breach of the second set of freeze wells2756A may be indicated. Measures may be taken to determine the locationof the breach in the second set of freeze wells 2756A. After determiningthe location of the breach, measures may be taken to stop the breach. Inan embodiment, an additional freeze well or freeze wells may be insertedinto the formation between the second set of freeze wells 2756A and theset of monitor and/or injection wells 606 to seal the breach.

[2365] In many embodiments, monitor and/or injection wells 606 may notdetect a breach in the frozen barrier formed by the first set of freezewells 2756 during the in situ conversion process. To clean the treatmentarea after completion of the in situ conversion processes, the first setof freeze wells 2756 may be deactivated. Fluid may be introduced throughmonitor and/or injection wells 606 to raise the temperature of thefrozen barrier and force fluid back towards treatment area 2750. Thefluid forced into treatment area 2750 may be produced from productionwells in the treatment area. If a breach of the frozen barrier formed bythe first set of freeze wells 2756 is detected during the in situconversion process, monitor and/or injection wells 606 may be used toremediate the area between the first set of freeze wells 2756 and thesecond set of freeze wells 2756A before, or simultaneously with,deactivating the first set of freeze wells. The ability to maintain thefrozen barrier formed by the second set of freeze wells 2756A after insitu conversion of hydrocarbons in treatment area 2750 is complete mayallow for cleansing of the treatment area with little or no possibilityof spreading contaminants beyond the second set of freeze wells 2756A.

[2366] The set of monitor and/or injection wells 606 may be positionedat a distance between the first set of freeze wells 2756 and the secondset of freeze wells 2756A to inhibit the monitor and/or injection wellsfrom becoming frozen. In some embodiments, some or all of the monitorand/or injection wells 606 may include a heat source or heat sources(e.g., an electric heater, circulated fluid line, etc.) sufficient toinhibit the monitor and/or injection wells from freezing due to the lowtemperature zones created by freeze wells 2756 and freeze wells 2756A.

[2367] In some in situ conversion process embodiments, a treatment areamay be treated sequentially. An example of sequentially treating atreatment area with different processes includes installing a pluralityof freeze wells within a formation around a treatment area. Pumpingwells are placed proximate the freeze wells within the treatment area.After a low temperature zone is formed, the pumping wells are engaged toreduce water content in the treatment area. After the pumping wells havereduced the water content, the low temperature zone expands to encompasssome of the pumping wells. Heat is applied to the treatment area usingheat sources. A mixture is produced from the formation. After a majorityof recoverable liquid hydrocarbons is recovered from the formation,synthesis gas generation is initiated. Following synthesis gasgeneration, the treatment area is used as a storage unit for fluidsdiverted from other treatment areas within the formation. The divertedfluids are produced from the treatment area. Before the low temperaturezone is allowed to thaw, the treatment area is remediated. A firstportion of a low temperature zone surrounding the pumping wells isallowed to thaw, exposing an unaltered portion of the formation. Wateris provided to a second portion of a low temperature zone to form afrozen barrier zone. A drive fluid is provided to the treatment areathrough the pumping wells. The drive fluid may move some fluidsremaining in the formation towards wells through which the fluids areproduced. This movement may be the result of steam distillation oforganic compounds, leaching of inorganic compounds into the drive fluidsolution, and/or the force of the drive fluid “pushing” fluids from thepores. Drive fluid is injected into the treatment area until the removeddrive fluid contains concentrations of the remaining fluids that fallbelow acceptable levels. After remediation of a treatment area, carbondioxide is injected into the treatment area for sequestration.

[2368] An alternate example of formation use includes a plurality offreeze wells placed within a formation surrounding a treatment area. Alow temperature zone may be formed around the treatment area. Pumpingwells, heat sources, and production wells are disposed within thetreatment area. Hot water, or water heated in situ by heat sources, maybe introduced into the treatment area to solution mine portions of theformation adjacent to selected wells. After solution mining, thetreatment area may be dewatered. The temperature of the treatment areamay be raised to pyrolysis temperatures, and pyrolysis products may beproduced from the treatment area.

[2369] After pyrolysis, the treatment area may be subjected to asynthesis gas generation process. After synthesis gas generation, thetreatment area may be cleaned. A drive fluid (e.g., water and/or steam)may be introduced into the treatment area to remove (e.g., by steamdistillation) hydrocarbons out of the treatment area. The drive fluidmay be introduced into the treatment area from an outer perimeter of thetreatment area. The drive fluid and any materials in front of, orentrained in, the drive fluid may be produced from production wells inthe interior of the treatment area. After cleaning, the treatment areamay be used as storage for selected products, as an emergency storagefacility, as a carbon dioxide sequestration bed, or for other uses.

[2370] In certain embodiments, adjacent treatment areas may beundergoing different processes concurrently within separate lowtemperature zones. These differing processes may have variedrequirements, for example, temperature and/or required constituents,which may be added to the section. In an embodiment, a low temperaturezone may be sufficient to isolate a first treatment area from a secondtreatment area. An example of differing conditions required by twoprocesses includes a first treatment area undergoing production ofhydrocarbons at an average temperature of about 310° C. A secondtreatment area adjacent to the first may undergo sequestration, aprocess, which depending on the component being sequestered, may beoptimized at a temperature less than about 100° C. Alternatively,providing a barrier to both mass and heat transfer may be necessary insome embodiments. A frozen barrier zone may be utilized to isolate atreatment area from the surrounding formation both thermally andhydraulically. For example, a first treatment area undergoing pyrolysisshould be isolated both thermally and hydraulically from a secondtreatment area in which fluids are being stored.

[2371] As depicted in FIG. 403 and FIG. 404A, dewatering wells 1978 maysurround treatment area 2750. Dewatering wells 1978 that surroundtreatment area 2750 may be used to provide a barrier to fluid flow intothe treatment area or migration of fluid out of the treatment area intosurrounding formation. In an embodiment, a single ring of dewateringwells 1978 surrounds treatment area 2750. In other embodiments, two ormore rings of dewatering wells surround a treatment area. In someembodiments that use multiple rings of dewatering wells 1978, a pressuredifferential between adjacent dewatering well rings may be minimized toinhibit fluid flow between the rings of dewatering wells. Duringprocessing of treatment area 2750, formation water removed by dewateringwells 1978 in outer rings of wells may be substantially the same asformation water in areas of the formation not subjected to in situconversion. Such water may be released with no treatment or minimaltreatment. If removed water needs treatment before being released, thewater may be passed through carbon beds or otherwise treated beforebeing released. Water removed by dewatering wells 1978 in inner rings ofwells may contain some hydrocarbons. Water with significant amounts ofhydrocarbon may be used for synthesis gas generation. In someembodiments, water with significant amounts of hydrocarbons may bepassed through a portion of formation that has been subjected to in situconversion. Remaining carbon within the portion of the formation maypurify the water by adsorbing the hydrocarbons from the water.

[2372] In some embodiments, an outer ring of wells may be used toprovide a fluid to the formation. In some embodiments, the providedfluids may entrain some formation fluids (e.g., vapors). An inner ringof dewatering wells may be used to recover the provided fluids andinhibit the migration of vapors. Recovered fluids may be separated intofluids to be recycled into the formation and formation fluids. Recycledfluids may then be provided to the formation. In some embodiments, apressure gradient within a portion of the formation may increaserecovery of the provided fluids.

[2373] Alternatively, an inner ring of wells may be used for dewateringwhile an outer ring is used to reduce an inflow of groundwater. Incertain embodiments, an inner ring of wells is used to dewater theformation and fluid is pumped into the outer ring to confine vapors tothe inner area.

[2374] Water within treatment area 2750 may be pumped out of thetreatment area prior to or during heating of the formation to pyrolysistemperatures. Removing water prior to or during heating may limit thewater that needs to be vaporized by heat sources so that the heatsources are able to raise formation temperatures to pyrolysistemperatures more efficiently.

[2375] In some embodiments, well spacing between dewatering wells 1978may be arranged in convenient multiples of heater and/or production wellspacing. Some dewatering wells may be converted to heater wells and/orproduction wells during in situ processing of a hydrocarbon containingformation. Spacing between dewatering wells may depend on a number offactors, including the hydrology of the formation. In some embodiments,spacing between dewatering wells may be 2 m, 5 m, 10 m, 20 m, orgreater.

[2376] A spacing between dewatering wells and ICP wells, such as heatsources or production wells, may need to be large. The spacing may needto be large so that the dewatering wells and the in situ process wellsare not significantly influenced by each other. In an embodiment, aspacing between dewatering wells and in situ process wells may need tobe 30 m or more. Greater or lesser spacings may be used depending onformation properties. Also, a spacing between a property line anddewatering wells may need to be large so that dewatering does notinfluence water levels on adjacent property.

[2377] In some embodiments, a perimeter barrier or a portion of aperimeter barrier may be a grout wall, a cement barrier, and/or a sulfurbarrier. For shallow formations, a trench may be formed in the formationwhere the perimeter barrier is to be formed. The trench may be filledwith grout, cement, and/or molten sulfur. The material in the trench maybe allowed to set to form a perimeter barrier or a portion of aperimeter barrier.

[2378] Some grout, cement, or sulfur barriers may be formed in drilledcolumns along a perimeter or portion of a perimeter of a treatment area.A first opening may be formed in the formation. A second opening may beformed in the formation adjacent to the first opening. The secondopening may be formed so that the second opening intersects a portion ofthe first opening along a portion of the formation where a barrier is tobe formed. Additional intersecting openings may be formed so that aninterconnected opening is formed along a desired length of treatmentarea perimeter. After the interconnected openings are formed, a portionof the interconnected opening adjacent to where a barrier is to beformed may be filled with material such as grout, cement, and/or sulfur.The material may be allowed to set to form a barrier.

[2379] In situ treatment of formations may significantly alter formationcharacteristics such as permeability and structural strength. Productionof hydrocarbons from a formation corresponds to removal of hydrocarboncontaining material from the formation. Heat added to the formation may,in some embodiments, fracture the formation. Removal of hydrocarboncontaining material and formation of fractures may influence thestructural integrity of the formation. Selected areas of a treatmentarea may remain untreated to promote structural integrity of theformation, to inhibit subsidence, and/or to inhibit fracturepropagation.

[2380]FIG. 379 depicts a formation separated into a number of treatmentareas 2750. Freeze wells 2756 surrounding treatment areas 2750 may formlow temperature zones around the treatment areas. Formation materialwithin the low temperature zones may be untreated formation materialthat is not exposed to high temperatures during an in situ conversionprocess. Formation water may be frozen in the low temperature zone. Thefrozen water may provide additional structural strength to the formationduring the in situ conversion process. After completion of processingand use of a treatment area, maintenance of the low temperature zone maybe ended and temperature of material within the low temperature zone mayreturn to ambient conditions. The untreated formation material that wasin the low temperature zone may provide structural strength to theformation. The regions of untreated formation may inhibit subsidence ofthe formation.

[2381] In some embodiments of in situ conversion processes, portions ofa formation within a treatment area may not be subjected to temperatureshigh enough to pyrolyze or otherwise significantly change properties ofthe formation. Untreated portions of the formation may stabilize theformation and inhibit subsidence of the formation or overburden. In atreatment area, heat sources are generally placed in patterns withregular spacings between adjacent wells. The spacings may be smallenough to allow superposition of heat between adjacent heat sources. Thesuperposition of heat allows the formation to reach high temperatures. Aregular pattern of heat sources may promote relatively uniform heatingof the treatment area.

[2382] In some embodiments, a disruption of a regular heat sourcepattern may leave sections of formation within a treatment areaunprocessed. A large distance may separate heat sources from sections ofthe formation that are to remain untreated. The distance should allowthe untreated section to be minimally influenced by adjacent heatsources. The distance may be 20 m, 25 m, or greater. In an embodiment ofan in situ treatment process that uses a triangular pattern of heatsources, a well unit (e.g., three heat sources) may be periodicallyomitted from the pattern to leave an untreated portion of formation whenthe formation is subjected to in situ conversion. In other embodiments,more wells than a single unit of wells may be omitted from the pattern(e.g., 4, 5, 6, or more heat source wells may be periodically omittedfrom an equilateral triangle heat source pattern).

[2383] In some embodiments, selected wellbores of a regular heat sourcepattern may be utilized to maintain untreated sections of formationwithin the pattern. A heat transfer fluid may be placed or circulatedwithin casings placed in the selected wellbores. The heat transfer fluidmay maintain adjacent portions of the formation at low enoughtemperatures that allow the portions to be uninfluenced or minimallyinfluenced by heat provided to the formation from adjacent heat sources.The use of selected wellbores to maintain untreated portions of theformation within a treatment area may advantageously eliminate the needto make wellbore pattern alterations during well installation.

[2384] In some embodiments, water may be used as a heat transfer fluidplaced or circulated in selected casings to maintain untreated portionsof a formation. In some embodiments, the heat transfer fluid circulatedin selected casings to maintain untreated portions of formation mayinclude refrigerant utilized to form a low temperature zone around atreatment area. The refrigerant may be circulated in the selected wellsprior to initiation of formation heating so that low temperature zonesare formed around the selected freeze wells. Water in the formation mayfreeze in columns around the selected wells. Heating of the formationmay reduce the size of the columns around the freeze wells, but thefreeze wells should maintain frozen, untreated portions of the formationwithin a heated portion of the formation. The untreated portions mayprovide structural strength to the formation during an in situconversion process and after the in situ conversion process iscompleted.

[2385] Vapor processing facilities that treat production fluid from aformation may include facilities for treating generated hydrogen sulfideand other sulfur containing compounds. The sulfur treatment facilitiesmay utilize a modified Claus process or other process that produceselemental sulfur. Sulfur may be produced in large quantities at an insitu conversion process site.

[2386] Some of the sulfur produced may be liquefied and placed (e.g.,injected) in a spent formation. Stabilizers and other additives may beintroduced into the sulfur to adjust the properties of the sulfur. Forexample, aggregate such as sand, corrosion inhibitors, and/orplasticizers may be added to the molten sulfur. U.S. Pat. No. 4,518,548and U.S. Pat. No. 4,428,700, which are both incorporated by reference asif fully set forth herein, describe sulfur cements.

[2387] A spent formation may be highly porous and highly permeable.Liquefied sulfur may diffuse into pore space within the formation formedby thermally processing hydrocarbons within the formation. The sulfurmay solidify in the formation when the sulfur cools below the meltingtemperature of sulfur (approximately 115° C.). Solidified sulfur mayprovide structural strength to the formation and inhibit subsidence ofthe formation. Solidified sulfur in pore spaces within the formation mayprovide a barrier to fluid flow. If needed at a future time, sulfur maybe produced from the formation by heating the formation and removing thesulfur from the formation.

[2388] In some in situ conversion process embodiments, molten sulfur maybe placed in a formation to form a perimeter barrier around a portion ofthe formation to be subjected to pyrolysis. The perimeter barrier formedby solidified sulfur may provide structural strength to the formation.The perimeter barrier may need to be located a large distance away fromICP wells used during in situ conversion so that heat applied to thetreatment area does not affect the sulfur barrier. In some embodiments,the perimeter barrier may be 20 m, 30 m, or farther away from heatsources of an in situ conversion process system.

[2389] Sulfur barriers may be used in conjunction with a low temperaturezone formed by freeze wells. A low temperature zone, or freeze wall, maybe formed to provide a barrier to fluid flow into or out of a treatmentarea that is subjected to an in situ conversion process. The lowtemperature zone may also provide structural strength to the formationbeing treated. After the treatment area is processed, water or otherfluid may be introduced into the formation to remediate any contaminantswithin the treatment area. Heat may be recovered from the formation byremoving the water or other fluid from the formation and utilizing theheat transferred to the water or fluid for other purposes. Recoveringheat from the formation may reduce the temperature of the formation to atemperature in the vicinity of the melting temperature of sulfuradjacent to the low temperature zone.

[2390] After a temperature of the treatment area is reduced to about thetemperature of molten sulfur, molten sulfur may be introduced into theformation adjacent to the low temperature zone formed by freeze wells,and the molten sulfur may be allowed to diffuse into the formation. Inthe embodiment depicted in FIG. 382, the molten sulfur may be introducedinto the formation through dewatering well 1978. The molten sulfur maysolidify against the frozen barrier formed by freeze well 2756. Aftersolidification of the sulfur, maintenance of the low temperature zonemay be reduced or stopped.

[2391] Solid sulfur within pore spaces may inhibit fluid from migratingthrough the sulfur barrier. For example, carbon dioxide may be adsorbedonto carbon remaining in a formation that has been processed using an insitu conversion process. If water migrates into the formation, the watermay desorb the stored carbon dioxide from the formation. Sulfur injectedinto wells may solidify in pore spaces within the formation to form asulfur cement barrier. The sulfur cement barrier may inhibit watermigration into the formation. The barrier formed by the sulfur mayinhibit removal of stored carbon dioxide from the formation. In someembodiments, sulfur may be introduced throughout a formation instead ofjust as a perimeter barrier. Sulfur may be stored or used to inhibitsubsidence of the formation.

[2392] In some instances, shut-in management of the in situ treatment ofa formation may become necessary. “Shut-in” may be a reduction orcomplete termination of production from a formation undergoing in situtreatment. Adverse events of any kind and/or scheduled maintenance mayrequire shut-in of an in situ treatment process. For example, adverseevents may include malfunctioning or nonfunctioning treatmentfacilities, lack of transport facilities to move products away from theproject, breakthrough to the surface or an aquifer, and/orsociopolitical events not directly related to a project.

[2393] Generally, thermal conduction and conversion of hydrocarbonsduring in situ treatment are relatively slow processes. Therefore,shut-in of production may require a relatively long period of time. Forexample, at least some hydrocarbons in the formation may continue to beconverted for months or years after heating from the heat sources isterminated. Consequently, hydrocarbons and other vapors may continue tobe generated, accompanied by a build up of fluid pressure in theformation. Fluid pressure in the formation may exceed the fracturingstrength of the formation and create fractures. As a result,hydrocarbons and other vapors, which may include hydrogen sulfide, maymigrate through the fractures to the surrounding formation, potentiallyreaching groundwater or the surface.

[2394] Shut-in management of an in situ treatment process may include avariety of steps that alleviate problems associated with shut-in of theprocess. In one embodiment, substantially all heating from heat sources,including heater wells and thermal injection, may be terminated.Termination of heating is particularly important if the adverse event orshut down may be of long duration. In addition, substantially allhydrocarbon vapors generated may be produced from the formation. Theproduced hydrocarbon vapors may be flared. “Flaring” is oxidation orburning of fluids produced from a formation. It is particularlyadvantageous for complete combustion of H₂S to take place. Furthermore,it is desirable to flare methane since methane may be a much strongergreenhouse gas than CO₂.

[2395] In certain embodiments, the fluid pressure in the formation maybe maintained below a safe level. The safe fluid pressure level may bebelow an established threshold at which fracturing and breakthroughoccur in the formation. The fluid pressure in the formation may bemonitored by several methods, for example, by passive acousticmonitoring to detect fracturing. “Passive acoustic monitoring” detectsand analyzes microseismic events to determine fracturing in a formation.In an embodiment, a short term response to excessive pressure build upmay be to release formation fluids to other storage (e.g., a spent, coolportion of the formation). Alternatively, formation fluids may beflared.

[2396] In some embodiments, produced formation fluid may be injected andstored in spent formations. A spent formation may be retainedspecifically for receiving produced fluids should a shut-in situationarise. Fluid communication between the spent formation and thesurrounding formation may be limited by a barrier (e.g., a frozenbarrier, a sulfur barrier, etc.). The barrier may inhibit flow of theproduced formation fluid from the spent formation. In an embodiment, thetemperature of the spent formation may be low enough to condense asubstantial portion of condensable fluids. There may be a correspondingdecrease in fluid pressure as formation fluid condenses in the spentformation. The decrease in fluid pressure and volume reduction mayincrease storage capacity of the spent formation. In an embodiment,subsequent heating of the spent formation may allow substantiallycomplete recovery of stored hydrocarbons.

[2397] In certain embodiments, produced formation fluid may be injectedinto relatively high temperature formations. The formation may haveportions with an average temperature high enough to convert asubstantial portion of the injected formation fluid to coke and H₂. H₂may be flared to produce water vapor in some embodiments.

[2398] In an embodiment, produced formation fluid may be injected intopartially produced or depleted formations. The depleted formations mayinclude oil fields, gas fields, or water zones with established seal andtrap integrity. The trapped formation fluid may be recovered at a latertime. In other embodiments, formation fluid may be stored in surfacestorage units.

[2399]FIG. 418 is a flow chart illustrating options for produced fluidsfrom a shut-in formation. Stream 2824 may be produced from shut-information 2826. Stream 2824 may be injected into cooled spent formation2828. Formation 2828 may be reheated at a later time to produce thestored formation fluid, as shown by stream 2830. In addition, stream2824 may be injected into hot formation 2832. A substantial portion ofthe fluids injected into formation 2832 may be converted to coke and H₂.The H₂ may be produced from formation 2832 as stream 2834 and flared.Alternatively, stream 2824 may be injected into depleted oil or gasfield or water zone 2836. Injected formation fluid may be produced at alater time, as stream 2838 illustrates. Furthermore, stream 2824 may bestored in surface storage facilities 2840.

[2400] After completion of an in situ conversion process, formations maybe subjected to additional treatment processes in preparation forabandonment. Processes which may be performed in a formation mayinclude, but are not limited to, recovery of thermal energy from theformation, removal of fluids generated during the in situ conversionprocess through injection of a fluid (water, carbon dioxide, drivefluid), and/or recovery of thermal energy from a frozen barrier orfreeze well.

[2401] Thermal energy may be recovered from formations through theinjection of fluids into the formation. Fluids may be injected and/orremoved through existing heater wells, dewatering wells, and/orproduction wells. In some embodiments, a portion of a formationsubjected to an in situ conversion process may be at an averagetemperature greater than about 300° C. The portion of the formation mayhave a relatively high porosity (e.g., greater than about 20%) and apermeability greater than about 0.3 darcy (e.g., 0.4 darcy, 0.6 darcy,0.9 darcy, 1 darcy, or greater) due to the removal of hydrocarbons fromthe formation and thermal fracturing of the formation. The increasedporosity and permeability of the section may reduce the number of wellsneeded to inject and recover fluid. For example, water may be providedto or be removed from the formation using heater wells that allow, orhave been reworked to allow, fluid communication between the well andthe surrounding formation.

[2402] In some embodiments, fresh water may be injected into theformation. Alternatively, non-potable water, hydrocarbon containingwater, brine, acidic water, alkaline water, or combinations thereof maybe injected into the formation. Compounds in the water may be leftwithin the formation after the water is vaporized by heat within theformation. Some compounds within the water may be absorbed and/oradsorbed onto remaining material within the formation. Introduction ofseveral pore volumes of water may be needed to lower the averagetemperature in the formation below the boiling point of water. In anembodiment, water injection may include geothermal well and othertechnologies developed for utilizing the steam production from hightemperature subterranean formations.

[2403] In certain embodiments, applications of steam recovered from theformation may include direct use for power generation and/or use assensible energy in heat exchange mechanisms. In particular, thermalenergy from recovered steam may be used in project treatment facilities(e.g., in heat exchange units, in the desalinization process, or in thedistillation of produced water). The thermal energy from recovered steammay be used for solution mining of nearby mineral resources (e.g.,nahcolite, sulfur, phosphates, etc). Thermal energy from recovered steammay also be used in external industrial applications, such asapplications that require the use of large volumes of steam. Inaddition, thermal energy from recovered steam may be used for municipalpurposes (e.g., heating buildings) and for agricultural purposes (e.g.,heating hothouses or processing products).

[2404] In an in situ conversion process embodiment during a time priorto abandonment, substantially non-reactive gas (e.g., carbon dioxide)may be used as a heat recovery fluid. The substantially non-reactive gasmay be injected into the formation and heat within the formation may betransferred to the substantially non-reactive gas. In some embodiments,the substantially non-reactive gas may recover a substantial portion ofresidual treatment fluids (e.g., low molecular weight hydrocarbons). Thetreatment fluids may be separated from the substantially non-reactivegas at the surface of the formation. For example, some carbon dioxidemay be adsorbed onto the surface of the formation, displacing lowmolecular weight hydrocarbons. In an embodiment, carbon dioxide adsorbedonto formation surfaces during use as a heat recovery fluid may besequestered within the formation. After completion of heat recovery,additional carbon dioxide may be provided to the formation and adsorbedin formation pore spaces for sequestration.

[2405] In an in situ conversion process embodiment, recovery of storedheat in a formation with injected substantially non-reactive gas mayrequire more pore volumes of gas than would have been required had waterbeen used as the heat recovery fluid. This may be due to gases generallyhaving lower sensible heats than liquids. In addition, substantiallynon-reactive gas injection may require initial compression of theinjected gas stream. However, injection and recovery in the gas phasemay be easier than in the liquid phase. In certain embodiments, recoveryof heat from the formation may combine injection of water andsubstantially non-reactive gas. For example, substantially non-reactivegas injection may be performed first, followed by water injection.

[2406] In some embodiments, the formation may be cooled such that anaverage temperature of the formation is at least below the ambientboiling temperature of water. Injection and recovery of fluid may berepeated until the average temperature of the formation is below theambient boiling point at the fluid pressure in the formation.

[2407]FIG. 405 illustrates a schematic of an embodiment of heat recoveryfrom a formation previously subjected to an in situ conversion process.FIG. 405 includes formation 2842 with heat recovery fluid injectionwellbore 2844 and production wellbore 2846. The wellbores may be membersof a larger pattern of wellbores placed throughout a portion of theformation. The temperature in heated portions of the formation that areto be cooled may be between about 300° C. and about 1000° C. Thermalenergy may be recovered from the heated portions of the formation byinjecting a heat recovery fluid. Heat recovery fluid 2848, such as waterand/or carbon dioxide, may be injected into wellbore 2844. A portion ofinjected water may be vaporized to form steam. A portion of injectedcarbon dioxide may adsorb on the surface of the carbon in the formation.Gas mixture 2850 may exit continuously from wellbore 2846. Gas mixture2850 may include the heat recovery fluid (e.g., steam or carbondioxide), hydrocarbons, and/or components. Components and hydrocarbonsmay be separated from the gas mixture in a treatment facility. The heatrecovery fluid may be recycled back into the formation.

[2408] In an in situ conversion process embodiment, heat recovery fromthe formation may be performed in a batch mode. Injection of the heatrecovery fluid may continue for a period of time (e.g., until the porevolume of the portion of the formation is substantially filled). After aselected period of time subsequent to ceasing injection of heat recoveryfluid, gas mixture 2850 may be produced from the formation throughwellbore 2846. In an embodiment, the gas mixture may also exit throughwellbore 2844. The selected period of time may be, in some embodiments,about one month.

[2409] In one embodiment, gas mixture 2850 may be fed to surfaceseparation unit 2852. Separation unit 2852 may separate gas mixture 2850into heat recovery fluid 2854 and hydrocarbons and components 2856. Theheat recovery fluid may be used in power generation units 1798 or heatexchange mechanisms 2858. In another embodiment, gas mixture 2850 may befed directly from the formation to power generation units or heatexchange mechanisms. Injection of the heat recovery fluid may becontinued until a portion of the formation reaches a desiredtemperature. For example, if water is used as the heat recovery fluid,water injection may continue until the formation cools to, or is at atemperature below, the boiling point of water at formation pressure.

[2410] Thermal processing and increasing the permeability of a formationmay allow some components (e.g., hydrocarbons, metals and/or residualformation fluids) in-the formation to migrate from a treatment area toareas adjacent to the formation. Such components may be created duringthermal processing of the formation. Such components may be present inhigher quantities if the formation is not subjected to a synthesis gasgeneration cycle after pyrolysis. In one embodiment, a recovery fluidmay be introduced into the formation to remove some of the components.The recovery fluid may be provided to the formation prior to and/orafter cooling of the formation has begun. The recovery fluid mayinclude, but is not limited to, water, steam, hydrogen, carbon dioxide,air, hydrocarbons (e.g., methane, ethane, and/or propane), and/or acombustible gas. The provided recovery fluid may be recycled fromanother portion of the formation, another formation, and/or the portionof the formation being treated.

[2411] In some embodiments, a portion of the recovery fluid may reactwith one or more materials in the formation to volatize and/orneutralize at least some of the material. In some embodiments, therecovery fluid may force components in the formation to be produced.After production the recovery fluid may be provided to an energyproducing unit (e.g. turbine or combustor). For example, methane may beprovided to a portion of the formation. Heat within the formation maytransfer to the methane. The methane may cause production of a mixtureincluding heavier hydrocarbons (e.g., BTEX compounds). The mixture maybe provided to a turbine, where some of the mixture is combusted toproduce electricity. In some embodiments, water may be provided to theformation as a recovery fluid. Steam produced from the water mayentrain, distill, and/or drive components within the formation toproduction wells. In an embodiment, organic components may be producedfrom the formation either by steam distillation and/or entrainment insteam. In some embodiments, inorganic components may be entrained andproduced in condensed water in the formation. Water injection and steamrecovery may be continued until safe and permissible levels ofcomponents are achieved. Removal of these components may occur after anin situ conversion process is complete.

[2412] Remediation within a treatment area surrounded by a barrier(e.g., a frozen barrier) may inhibit the migration of components fromthe treatment area to the surrounding formation. A plurality of freezewells 2756 may be used to form frozen barrier 2768 and define a volumeto be treated within hydrocarbon containing material 2860, asillustrated in FIG. 406. Frozen barrier 2768 may inhibit fluid flow intoor out of treatment area 2862. In an in situ conversion processembodiment, a recovery fluid may be introduced into the formation nearfreeze wells 2756 after treatment is complete. Injection wells 606 usedfor injection of the recovery fluid may include, but are not limited to,pumping wells, heat sources, freeze wells, dewatering wells, and/orproduction wells that have been converted into injection wells. Incertain embodiments, wells used previously may have a sealed casing. Thesealed casing may be perforated to permit fluid communication betweenthe well and the surrounding formation. Recovery fluid may move some ofthe components in the formation towards one or more removal wells 2864.Removal wells 2864 may include wells that were converted from heatsources and/or production wells. In some embodiments, a recovery fluidmay be introduced into a treatment area through an innermost productionwell, or a production well ring, that is converted into an injectionwell.

[2413] In some embodiments, the recovery fluid may be introduced intothe formation after the frozen barrier zone has been partially thawed.When thawing the frozen barrier, thermal energy may be removed from thefrozen barrier by circulating various fluids through the freeze well.For example, a warm refrigerant may be injected into the freeze wellsystem to be cooled and used in a surface treatment unit, a freeze wellsystem, and/or other treatment area. As the temperature within thefreeze well increases, various other fluids (e.g., water, substantiallynon-reactive gas, etc.) may be utilized to raise the temperature of thefreeze well. Thawed freeze wells that are exposed may be converted foruse as injection wells 606 to introduce recovery fluid into theformation. Introduction of the recovery fluid may heat the regionadjacent to the inner row of freeze wells to an average temperature ofless than a pyrolysis temperature of hydrocarbon material in theformation. The heat from the recovery fluid may move mobilizedhydrocarbon and inorganic components. Movement of the hydrocarbon andinorganic components may be due in part to steam distillation of thefluids and/or entrainment. Introducing the recovery fluid at a pointwhere the formation was previously frozen ensures that the hydrocarbonmaterial at the injection well is unaltered. The unaltered hydrocarbonmaterial may be essentially in its original natural state. As such, theinjected fluid may move from a natural zone to the previously treatedarea and be produced. Thus, fluids formed during the treatment areremoved without spreading such fluids to other areas outside of thetreatment area. Alternatively, any well previously frozen in a frozenbarrier zone, such as a pumping well, may be thawed and used as aninjection well.

[2414] A volume of recovery fluid required to remediate a treatment areamay be greater than about one pore volume of the treatment area. Twopore volumes or more of recovery fluid may be introduced to remediatethe treatment area. In certain embodiments, injection of a recoveryfluid to remediate a treatment area may continue until concentrations ofcomponents in the removed recovery fluid are at acceptable levels deemedappropriate for a site. These acceptable levels may be based on baseline surveys, regulatory requirements, future potential uses of thesite, geology of the site, and accessibility. After one or morecomponents within a treatment area are removed or reduced to acceptablelevels, the treatment system for the formation, including the freezewells, may be deactivated. If a new barrier zone around a new treatmentarea is to be formed, heat may be transferred between hydrocarboncontaining material, in which a new barrier zone is to be formed, andthe initial freeze wells using a circulated heat transfer fluid. Usingdeactivated freeze wells to cool hydrocarbon containing material inwhich a low temperature zone is to be formed may allow for recovery ofsome of the energy expended to form and maintain the initial barrier. Inaddition, using thermal energy extracted from the initial barrier tocool hydrocarbon material in which a new barrier zone is to be formedmay significantly decrease a cost of forming the new barrier. In sometreatment system embodiments, a low temperature zone may be allowed toreach thermal equilibrium with a surrounding formation naturally.

[2415] In some in situ conversion process embodiments, the frozenbarrier may include an inner ring of freeze wells directly adjacent tothe treatment area and an outer ring of freeze wells directly adjacentto the untreated area. A region of the formation near the freeze wellsmay remain at a temperature below the freezing point of water duringpyrolysis and synthesis gas generation. In an embodiment, organiccomponents from pyrolysis may migrate through thermal fractures to aregion adjacent to the inner row of freeze wells. The contaminants maybecome immobilized in fractures and pores in the region due to therelatively low temperatures of the region.

[2416] Migration of contaminants from the treatment area may be reducedor prevented by inhibiting groundwater flow through the treatment area.For example, groundwater flow may be inhibited using a barrier such as afreeze wall and/or sulfur barriers. As a result, migration ofcontaminants may be reduced or eliminated even if contaminants weredissolved in formation pore water. In addition, it may be advantageousto inhibit groundwater flow to maintain a reduced state within theformation. Oxidized metals introduced into the formation fromgroundwater flow tend to have greater mobility and may be more likely tobe released.

[2417] An embodiment for inhibiting migration of contaminants may alsoinclude sealing off the mineral matrix and residual carbon byprecipitation or evaporation of a sealing mineral phase. The sealingmineral phase may inhibit dissolution of contaminants of fluids in theformation into groundwater.

[2418] Carbon dioxide may be produced during an in situ conversionprocess or during processing of the products produced by the in situconversion process (e.g., combustion). Control and/or reduction ofcarbon dioxide production from an in situ conversion process may bedesirable. “Carbon dioxide life cycle emissions,” as used herein, isdefined as the amount of CO₂ emissions from a product as it is produced,transported, and used.

[2419] A base line CO₂ life cycle emission level may be selected forproducts produced from an in situ conversion process. The formationconditions and/or process conditions may be altered to produce productsto meet the selected CO₂ base line life cycle emission level. In someembodiments, in situ conversion products may be blended to meet aselected CO₂ base line life cycle emission level. The CO₂ life cycleemission level of a selected product is defined as a number of kilogramsof CO₂ per joule of energy (kg CO₂/J).

[2420] A hydrogen cycle, a half-way cycle, and a methane cycle areexamples of processes that may be used to produce products with selectedCO₂ emission levels less than the total CO₂ emission level that would beproduced by direct production of natural gas from a gas reservoir. Incertain embodiments, products may be combined to produce a product witha selected CO₂ emission level less than the total CO₂ emission fromdirect production of natural gas. In other embodiments, cycles may beblended to produce products with a CO₂ emission level less than thetotal CO₂ emission from direct production of natural gas. For example,in an embodiment, a methane cycle may be used in one part of aproduction field and a half-way cycle may be used in another part of theproduction field. The products produced from these two processes may beblended to produce a product with a selected CO₂ emission level. Inother embodiments, other combinations of products from the hydrogencycle, the half-way cycle, and the methane cycle may be used to producea product with a selected CO₂ emission level.

[2421] In an in situ conversion process embodiment, a formation may betreated such that hydrocarbons in the formation are converted to adesired product. The product may be produced from the formation. In somein situ conversion process embodiments, the in situ conversion processmay be operated to produce a limited amount of carbon dioxide.

[2422] In an in situ conversion process embodiment, the in situconversion process may be operated so that a substantial portion of theproduct is molecular hydrogen. There may be little or no hydrocarbonfluid recovery. An in situ conversion process that operates at a hightemperature to produce a substantial portion of hydrogen may be a“hydrogen cycle process.” A portion of the hydrogen produced during thehydrogen cycle process may be used to fuel heat sources that raiseand/or maintain a temperature within the formation to a hightemperature.

[2423] During a hydrogen cycle process, a production well and formationadjacent to the production well may be heated to temperatures greaterthan about 525° C. At such temperatures, a substantial portion ofhydrocarbons present or that flow into the production well and formationadjacent to the production well may be reduced to hydrogen and coke.There may be minimal or no production of carbon dioxide or hydrocarbons.Hydrocarbons in formation fluid produced from the formation may berecycled back into the formation through injection wells to producehydrogen and coke. Hydrogen produced from a hydrogen cycle process maybe produced through heated production wells in the formation. A portionof the produced hydrogen may be used as a fuel for heat sources in theformation. A portion of the hydrogen may be sold or used in fuel cells.In some embodiments, coke produced during a hydrogen cycle process mayslowly fill pore space within the formation adjacent to the productionwell. The coke may provide structural strength to the formation. In someembodiments, the production wells may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of formed coke andallow for production of formation fluid. In some embodiments, a cokedproduction well may be blocked, and formation fluid may be produced fromother production wells.

[2424] A hydrogen cycle may allow for very low CO₂ life cycle emissionlevels. In some embodiments, a hydrogen cycle process may have a CO₂life cycle emission level of about 3.3×10⁻⁹ kg CO₂/J. In otherembodiments, a CO₂ life cycle emission level of the hydrogen cycleprocess may be less than about 1.6×10⁻¹⁰ kg CO₂/J.

[2425] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantially amixture of molecular hydrogen and methane. There may be little or noother hydrocarbons (i.e., ethane, propane, etc.). A process ofconverting hydrocarbons in a formation to a product that issubstantially molecular hydrogen and methane may be referred to as a“half-way cycle process.” A portion of the product may be used as a fuelfor heat sources that heat the formation to maintain and/or increase theformation temperature.

[2426] During a half-way cycle, production wells and formation adjacentto the production wells may be heated to temperatures from about 400° C.to about 525° C. A substantial portion of hydrocarbons present or thatflow into the production wells or formation adjacent to the productionwells may be reduced to molecular hydrogen and methane. The hydrogen andmethane may be produced as a mixture from the production wells. Producedhydrocarbons having carbon numbers greater than one may be recycled backinto the formation through injection wells to generate hydrogen andmethane. Formation adjacent to the production wells may slowly coke upduring a half-way cycle. When production through a production well fallsbelow a certain level, the production well may be blocked in. In someembodiments, the production well may be treated (e.g., by introducingsteam to generate synthesis gas) to remove a portion of the coke andallow for increased production through the well.

[2427] In an embodiment of a half-way cycle process, produced hydrogenand methane may be separated from other produced fluid. A portion of thehydrogen and methane may be used as a fuel for heat sources. Further,hydrogen may be separated from the methane of a portion not used asfuel. In some embodiments, a portion of the hydrogen may be used forhydrogenation in another portion of the formation and/or in treatmentfacilities. In some embodiments, hydrogen may be sold. In someembodiments, some or all produced methane may be used to fuel heatsources.

[2428] A mixture produced using a half-way cycle may have a CO₂ lifecycle emission level that is greater than a CO₂ life cycle emissionlevel of a hydrogen cycle. A mixture produced using a half-way cycle mayhave a CO₂ life cycle emission level of less than about 3.3×10⁻⁸ kgCO₂/J.

[2429] In an in situ conversion process embodiment, a portion offormation may be treated to produce a product that is substantiallymethane. A process of converting a substantial portion of hydrocarbonswithin a portion of formation to methane may be referred to as a“methane cycle.”

[2430] The producing wellbore and the formation proximate the producingwellbore may, in some embodiments, be heated to temperatures from about300° C. to about 500° C. For example, the producing wellbore may beheated to about 400° C. Pyrolysis in this temperature range may allow asubstantial portion of hydrocarbons in the formation to be converted tomethane. Hydrocarbons with carbon numbers greater than one produced fromthe formation may be recycled back into the formation through injectionwells to generate methane. The methane may be produced in a mixture fromthe heated wellbores. In an embodiment, the methane content may begreater than about 80 volume % of the produced fluids.

[2431] A mixture produced from a methane cycle may have a CO₂ life cycleemission level that is larger than the CO₂ life cycle emission level fora half-way cycle. In some embodiments of methane cycles, the CO₂ lifecycle emission levels are less than about 7.4×10⁻⁸ kg CO₂/J.

[2432] In an in situ conversion process embodiment, molecular hydrogenmay be produced on site using processes such as, but not limited to,Modular and Intensified Steam Reforming (MISR) and/or Steam MethaneReforming (SMR). The produced molecular hydrogen may be blended withother products to produce a product below a selected CO₂ emission level.The CO₂ produced using MISR or other processes may be sequestered in aformation.

[2433] After completion of pyrolysis and/or synthesis gas generationduring an in situ conversion process, at least a portion of theformation may be converted into a hot spent reservoir. The hot spentreservoir may have a temperature of greater than about 350° C. Theporosity may have increased by 20 volume % or more. In addition, apermeability in a hot spent reservoir may be greater than about 1 darcy,or in certain embodiments, greater than about 20 darcy. A hot spentreservoir may have a large open volume. The surface area within thevolume may have increased significantly due to the in situ conversionprocess. Utilization of the in situ conversion process may have requiredthe installation and use of production wells and heat sources spaced ata range between about 10 m and about 30 m. A barrier (e.g., freezewells) may also be present to inhibit migration of fluids to or from atreatment area in the formation.

[2434] In an in situ conversion process embodiment, a heated formation(e.g., a formation that has undergone substantial pyrolysis and/orsynthesis gas generation) may be used to produce olefins and/or otherdesired products. Hydrocarbons may be provided to (e.g., injected into)a heated portion of a formation. An in situ conversion process in aseparate portion of the formation may provide the source of thehydrocarbons. The formation temperature and/or pressure may becontrolled to produce hydrocarbons of a desired composition (e.g.,hydrocarbons with a C₂-C₇ carbon chain length). Temperature may becontrolled by controlling energy input into heat sources. Pressure maybe controlled by controlling the temperature in the formation and/or bycontrolling a rate of production of formation fluid from the formation.Pressure within a portion of a formation enclosed by a perimeter barrier(e.g., a frozen barrier and an impermeable overburden and underburden)may be controlled so that the pressure is substantially uniformthroughout the enclosed portion of formation.

[2435] Many different types of hydrocarbons may be provided to theheated formation as a feed stream. Examples of hydrocarbons include, butare not limited to, pitch, heavy hydrocarbons, asphaltenes, crude oil,naphtha, and/or condensable hydrocarbons (e.g., methane, ethane,propane, and butane). A portion of heavy and/or condensable hydrocarbonsintroduced into a heated portion of the formation may pyrolyze to formshorter chain compounds. The shorter chain compounds may have greatervalue than the longer chain compounds introduced into the portion offormation.

[2436] A portion of the hydrocarbons introduced into the formation mayreact to form olefins. An overall efficiency for producing olefins maybe relatively low (as compared to reactors designed to produce olefins),but the volume of heated formation and/or the availability of feed fromportions of the formation undergoing an in situ conversion process maymake production of olefins from a heated formation economically viable.

[2437] In certain embodiments, the temperature of a selected portion ofthe formation (e.g., near production wells) may be controlled so thathydrocarbon fluid flowing into the selected portion has an increasedchance of forming olefins. In certain embodiments, process conditionsmay be controlled such that the time period in which the compounds aresubjected to relatively higher temperatures is controlled. In certainembodiments, only a small portion of the formation (e.g., near theproduction wells) is at a high enough temperature to promote olefinformation. Olefins may be formed subsurface in the small portion, butthe olefins are produced quickly (e.g., before the olefins cancross-link in the formation and/or further react to form coke).

[2438] In an embodiment, olefins are produced from saturatedhydrocarbons. Formation of the olefins from saturated hydrocarbons alsoresults in the production of molecular hydrogen. In an embodiment,olefin production may include cracking saturated hydrocarbons in theformation and allowing the cracked hydrocarbons to further react in theformation (e.g., via alkylation or dimerization). The formation ofolefins may involve different reaction mechanisms. Any number of theolefin formation mechanisms may be present in the in situ conversionprocess. Water may be added to the formation for steam generation and/ortemperature control.

[2439] Examples of olefins produced by providing hydrocarbons to aheated formation may include, but are not limited to, ethene, propene,1-butene, 2-butene, higher molecular weight olefins, and/or mixturesthereof. The produced mixture may include from slightly over about 0weight % to about 80 weight % (e.g., from about 10-50 weight %) olefinsin a hydrocarbon portion of a produced mixture.

[2440] In an in situ conversion process embodiment, crude oil may beprovided to a heated portion of a formation. The crude oil may crack inthe heated portion to form a lighter, higher quality oil and an olefinportion. In an in situ conversion process embodiment, pitch and/orasphaltenes may be provided to a heated portion of a formation. Thepitch and/or asphaltenes may be in solution and/or entrained in asolvent. The solvent may be a hydrocarbon portion of a fluid producedfrom a portion of a formation subjected to an in situ conversionprocess. A portion of the pitch and/or asphaltenes and the solvent maybe converted in the formation to high quality hydrocarbons and/orolefins. Similarly, emulsions, bottoms, and/or undesired hydrocarboncompounds that are flowable, entrained in a flowable solution, ordissolved in a solvent may be introduced into a heated portion of aformation to upgrade the introduced fluids and/or produce olefins.

[2441] In some embodiments, a temperature in selected portions of aproduction well wellbore may be controlled to promote productionof-olefins. A portion of the wellbore adjacent to a heated portion ofthe formation may include a heater that maintains the temperature at anelevated temperature. A portion of the wellbore above the heated portionof the wellbore may include a heat transfer line that reduces thetemperature of fluid being removed through the wellbore to a temperaturebelow reaction temperatures of desired components within the wellbore(e.g., olefins). In some embodiments, transfer of heat from the fluidsin the wellbore to the overburden may reduce the temperature of fluidsin the wellbore quickly enough to obviate the need for a heat transferline in the wellbore.

[2442] In some in situ conversion process embodiments, hydrocarbonfeedstock introduced into a hot portion of a portion may have an APIgravity of less than about 20°. The hydrocarbon feedstock may be crackedin the heated portion to produce a plurality of products. The productsmay include olefins. Molecular hydrogen may also be produced along witha mixture of products. A temperature and/or a pressure of the heatedportion of the formation may be controlled such that a substantialportion of the produced product includes olefins. A hydrocarbon portionof the produced mixture may include from about 1 weight % to about 80weight % (e.g., from about 10-50 weight %) olefins.

[2443] In some in situ conversion process embodiments, a hydrocarbonmixture produced from a formation may be suitable for use as an olefinplant feedstock. Process conditions in a portion of a formation may beadjusted to produce a hydrocarbon mixture that is suitable for use as anolefin plant feedstock. The mixture should contain relatively shortchain saturated hydrocarbons (e.g., methane, ethane, propane, and/orbutane). To change formation conditions to produce a hydrocarbon mixturesuitable for use as an olefin plant feedstock, backpressure within theformation may be maintained at an increased level (i.e., production fromproduction wells may be low enough to result in an increase in pressurein the formation).

[2444] In some in situ conversion process embodiments, low molecularweight olefins (e.g., ethene and propene) may be produced during the insitu conversion process. Fluid produced may be routed through arelatively hot (e.g., greater than about 500° C.) subsurface zone beforethe fluid is allowed to cool. The fluid may crack at a high temperatureto produce low molecular weight olefins. The fluid should be subjectedto high temperature for only a short period of time to inhibit formationof methane, hydrogen, and/or coke from the low molecular weight olefins.

[2445] In some in situ conversion process embodiments, olefin productionyield may be facilitated from a formation. Continued processing orrecycling of the non-olefinic C₂+ products in the in situ conversionprocess may maximize ethene and/or propene yield. Control of thetemperature and residence time within a portion of the formation may beused to maximize non-olefinic C₂+ hydrocarbons and hydrogen content.Some olefins may be produced in this cycle and separated from theproduced fluid. The non-olefinic portion may be recycled to a secondsection of the formation that includes production wells that are heated.A portion of the introduced hydrocarbons may be converted into olefinsby the heated production wells to increase the yield of olefins obtainedfrom the formation.

[2446] In some in situ conversion process embodiments, linear alphaolefins in the C₄-C₃₀ range may be produced from shale oil. Formationconditions may be controlled to facilitate formation and production ofolefins in a desired range (e.g., C₆-C₁₆ alpha olefins). Shale oil mayproduce paraffinic (i.e., waxy) and linear compounds during the in situconversion process. Linear alpha olefins may be produced from the insitu conversion process by varying the temperature, residence time,and/or pressure in the formation being treated. Some other types ofhydrocarbon containing formations may promote the production of shorterchain olefins. For example, kerogen containing formations may producelower molecular weight olefins (e.g., ethene, propene, butene, and/orisomers thereof) instead of longer chain olefins (e.g., chains havinggreater than 5 carbon atoms).

[2447] Some in situ conversion processes may be run at sufficientpressure to generate a desirable steam cracker feed. A desirable steamcracker feed may be a feed with relatively high hydrocarbon content(e.g., a relatively high alkane content) and relatively low oxygen,sulfur, and/or nitrogen content. A desirable steam cracker feed mayreduce the need to treat the stream before processing in a steam crackerunit. Therefore, the desirable feed may be run directly from the in situconversion process to a steam cracker unit. The steam cracker unit mayproduce olefins from the feed stream.

[2448] In an in situ conversion process embodiment, a heated formationmay be used to upgrade materials. Materials to be upgraded may beproduced from the same portion of the formation and recycled, producedfrom other formations, or produced from other portions of the sameformation.

[2449] During some in situ conversion process embodiments in selectedformations (e.g., in tar sands formations), only a selected portion of aformation may be heated to relatively high temperatures (e.g., atemperature sufficient to cause pyrolysis). Other portions of theformation may still produce heavy hydrocarbons but may not be heated, ormay only be partially heated (e.g., by steam, heat sources, or othermechanisms). The heavy hydrocarbons produced from the other less heatedor unheated portions of the formation may be introduced into the portionof the formation that is heated to a relatively high temperature. Thehigh temperature portion of the formation may upgrade the introducedheavy hydrocarbons. Energy savings may be achieved since only a portionof the formation is heated to a relatively high temperature.

[2450] In an embodiment, surface mined tar (e.g., from tar sands) may beupgraded in a heated formation. The tar sands may be processed toproduce separated hydrocarbons (e.g., tar). A portion of the tar may beheated, entrained, and/or dissolved in a solvent to produce a flowablefluid. The solvent may be a portion of hydrocarbon fluid produced fromthe formation. The flowable fluid may be introduced into the heatedportion of the formation.

[2451] Emulsions may be produced during some metal processing and/orhydrocarbon processing procedures. Some emulsions may be flowable. Otheremulsions may be made flowable by the introduction of heat and/or acarrier fluid. The carrier fluid may be water and/or hydrocarbon fluid.The hydrocarbon fluid may be a fluid produced during an in situ process.A flowable emulsion may be introduced into a heated portion of aformation being subjected to in situ processing. In some embodiments,the heated portion may break the emulsion. The components of theemulsion may pyrolyze or react (e.g., undergo synthesis gas reactions)in the heated formation to produce desired products from productionwells. In some embodiments, the emulsion or components of the emulsionmay remain in the formation.

[2452] Upgrading may include, but is not limited to, changing a productcomposition, a boiling point, or a freezing point. Examples of materialsthat may be upgraded include, but are not limited to, heavyhydrocarbons, tar, emulsions (e.g., emulsions from surface separation oftar from sand), naphtha, asphaltenes, and/or crude oil. In certainembodiments, surface mined tar may be injected into a formation forupgrading. Such surface mined tar may be partially treated, heated, oremulsified before being provided to a formation for upgrading. Thematerial to be upgraded may be provided to the heated portion of theformation. The material may be upgraded in the formation. For example,upgrading may include providing heavy hydrocarbons having an API gravityof less than about 20°, 15°, 10°, or 5° into a heated portion of theformation. The heavy hydrocarbons may be cracked or distilled in theheated portion. The upgraded heavy hydrocarbons may have an API gravityof greater than about 20° (or above about 25° or above 30°). Theupgraded heavy hydrocarbons may also have a reduced amount of sulfurand/or nitrogen. A property of the upgraded hydrocarbons (e.g., APIgravity or sulfur content) may be measured to determine the relativeupgrading of the hydrocarbons.

[2453] In some in situ conversion process embodiments, fluid producedfrom a formation may be fractionated in an above ground facility toproduce selected components. The relatively heavier molecular weightcomponents (e.g., bottom fractions from distillation columns) may berecycled into a formation. The heated formation may upgrade therelatively heavier molecular weight components.

[2454] In some in situ conversion process embodiments, heavyhydrocarbons may be produced at a first location. The heavy hydrocarbonsmay be diluted with a diluent to enable the heavy hydrocarbons to bepumped or otherwise transported to a different location. The mixture ofheavy hydrocarbons and diluent may be separated at the heated formationprior to providing the heavy hydrocarbons mixture to the heatedformation for upgrading. Alternately, the mixture of heavy hydrocarbonsand diluent may be directly injected into a heated formation forupgrading and separation in the heated formation. In certainembodiments, a hot fluid (e.g., steam) may be added to the heavyhydrocarbons mixture to allow fluid cracking in the heated formation.Steam may inhibit coking in the formation, lessen the partial pressureof hydrocarbons in the formation, and/or provide a mechanism to sweepthe formation. Controlling the flow of steam may provide a mechanism tocontrol the residence time of the hydrocarbons in the heated formation.The residence time of the hydrocarbons in the heated formation may beused to control or adjust the molecular weight and/or API gravity of aproduct produced from the heated formation.

[2455] In an in situ conversion process embodiment, heavy hydrocarbonsmay be produced from a heated formation. The heavy hydrocarbons may berecycled back into the same formation to be upgraded. The upgradedproducts may be produced from the formation. In another embodiment, theheavy hydrocarbon may be produced from one formation and upgraded inanother formation at a different temperature. The residence time andtemperature of the formation may be controlled to produce a desirableproduct. For example, a portion of fluid initially produced from a tarsands formation undergoing an in situ conversion process may be heavyhydrocarbons, especially if the hydrocarbons are produced from arelatively deep depth within a hydrocarbon containing layer of the tarsands formation. The produced heavy hydrocarbons may be reintroducedinto the formation through or adjacent to a heat source to facilitateupgrading of the heavy hydrocarbons.

[2456] In an in situ conversion process embodiment, crude oil producedfrom a formation by conventional methods may be upgraded in a heatedformation of the in situ conversion process system. The crude oil may beprovided to a heated portion of the formation to upgrade the oil. Insome embodiments, only a heavy fraction of the crude oil may beintroduced into the heated formation. The heated portion of theformation may upgrade the quality of the introduced portion of the oiland/or remove some of the undesired components within the introducedportion of the crude oil (e.g., sulfur and/or nitrogen).

[2457] In some embodiments, hydrogen or any other hydrogen donor fluidmay be added to heavy hydrocarbons injected into a heated formation. Thehydrogen or hydrogen donor may increase cracking and upgrading of theheavy hydrocarbons in the heated formation. In certain embodiments,heavy hydrocarbons may be injected with a gas (e.g., hydrogen or carbondioxide) to increase and/or control the pressure within the heatedformation.

[2458] In an in situ conversion process embodiment, a heated portion ofa formation may be used as a hydrotreating zone. A temperature andpressure of a portion of the formation may be controlled so thatmolecular hydrogen is present in the hydrotreating zone. For example, aheat source or selected heat sources may be operated at hightemperatures to produce hydrogen and coke. The hydrogen produced by theheat source or selected heat sources may diffuse or be drawn by apressure gradient created by production wells towards the hydrotreatingzone. The amount of molecular hydrogen may be controlled by controllingthe temperature of the heat source or selected heat sources. In someembodiments, hydrogen or hydrogen generating fluid (e.g., hydrocarbonsintroduced through or adjacent to a hot zone) may be introduced into theformation to provide hydrogen for the hydrotreating zone.

[2459] In an in situ conversion process embodiment, a compound orcompounds may be provided to a hydrotreating zone to hydrotreat thecompound or compounds. In some embodiments, the compound or compoundsmay be generated in the formation by pyrolysis reactions of nativehydrocarbons. In other embodiments, the compound or compounds may beintroduced into the hydrotreating zone. Examples of compounds that maybe hydrotreated include, but are not limited to, oxygenates, olefins,nitrogen containing carbon compounds, sulfur containing carboncompounds, crude oil, synthetic crude oil, pitch, hydrocarbon mixtures,and/or combinations thereof.

[2460] Hydrotreating in a heated formation may provide advantages overconventional hydrotreating. The heated reservoir may function as a largehydrotreating unit, thereby providing a large reactor volume in which tohydrotreat materials. The hydrotreating conditions may allow thereaction to be run at low hydrogen partial pressures and/or at lowtemperatures (e.g., less than about 0.007 to about 1.4 bars or about0.14 to about 0.7 bars partial pressure hydrogen and/or about 200° C. toabout 450° C. or about 200° C. to about 250° C.). Coking within theformation generates hydrogen, which may be used for hydrotreating. Eventhough coke may be produced, coking may not cause a decrease in thethroughput of the formation because of the large pore volume of thereservoir.

[2461] The heated formation may have lower catalytic activity forhydrotreating compared to commercially available hydrotreatingcatalysts. The formation provides a long residence time, large volume,and large surface area, such that the process may be economical evenwith lower catalytic activity. In some formations, metals may bepresent. These naturally present metals may be incorporated into thecoke and provide some catalytic activity during hydrotreating.Advantageously, a stream generated or introduced into a hydrotreatingzone does not need to be monitored for the presence of catalystdeactivators or destroyers.

[2462] In an embodiment, the hydrotreated products produced from an insitu hydrotreating zone may include a hydrocarbon mixture and aninorganic mixture. The produced products may vary depending upon, forexample, the compound provided. Examples of products that may beproduced from an in situ hydrotreating process include, but are notlimited to, hydrocarbons, ammonia, hydrogen sulfide, water, or mixturesthereof. In some embodiments, ammonia, hydrogen sulfide, and/oroxygenated compounds may be less than about 40 weight % of the producedproducts.

[2463] In an in situ conversion process embodiment, a heated formationmay be used for separation processes. FIG. 407 illustrates an embodimentof a temperature gradient formed in a selected section of heatedformation 2866. Formation temperatures may decrease radially from heatsource 508 through the selected section. A fluid (either products fromvarious surface processes and/or products from other sources such ascrude oil) may be provided through injection well 606. The fluid maypass through heated formation 2866. Some production wells 512 may belocated at various positions along the temperature gradient. For vaporphase production wells, different products may be produced fromproduction wells that are at different temperatures. The ability toproduce different compositions from production wells depending on thetemperature of the production well may allow for production of a desiredcomposition from selected wells based on boiling points of fluids withinthe formation. Some compounds with boiling points that are below thetemperature of a production well may be entrained in vapor and producedfrom the; production well.

[2464]FIG. 408 illustrates an embodiment for separating hydrocarbonmixtures in a heated portion of formation 2868. Temperature and/orpressure of the heated portion may be controlled by heat source 508. Ahydrocarbon mixture may be provided through injection well 606 into aportion of the formation that is cooler than a portion of the formationcloser to heat sources or production wells. In a cooler portion offormation 2868, relatively heavy molecular weight products may condenseand remain in the formation. After separation of a desired quantity ofhydrocarbon mixture, the cooler portion of the formation may be heatedto result in pyrolysis of a portion of the heavy hydrocarbons to desiredproducts and/or mobilization of a portion of the heavy hydrocarbons toproduction well 512.

[2465] In an embodiment, a portion of a formation may be shut in atselected times to provide control of residence time of the products inthe subsurface formation. Shutting in a portion of the formation by notproducing fluid from production wells may result in an increase inpressure in the formation. The increased pressure may result inproduction of a lighter fluid from the formation when production isresumed. Different products may be produced based on the residence timeof fluids in the formation.

[2466] Once a formation has undergone an in situ conversion process,heat from the process may remain within the formation. Heat may berecovered from the formation using a heat transfer fluid. Heat transferfluids used to recover energy from a hydrocarbon containing formationmay include, but are not limited to, formation fluids, product streams(e.g., a hydrocarbon stream produced from crude oil introduced into theformation), inert gases, hydrocarbons, liquid water, and/or steam. FIG.409 illustrates an embodiment for recovering heat remaining in formation2870 by providing a product stream through injection well 606. Heatremaining in the formation may transfer to the product stream. Theformation heat may be controlled with heat source 508. The heatedproduct stream may be produced from the formation through productionwell 512. The heat of the product stream may be transferred to anynumber of surface treatment units 2872 or to other formations.

[2467] In an in situ conversion process embodiment, heat recovered fromthe formation by a heat transfer fluid may be directed to surfacetreatment units to utilize the heat. For example, a heat transfer fluidmay flow to a steam-cracking unit. The heat transfer fluid may passthrough a heat exchange mechanism of the steam-cracking unit to transferheat from the heat transfer fluid to the steam-cracking unit. Thetransferred heat may be used to vaporize water or as a source of heatfor the steam-cracking unit.

[2468] In some in situ conversion process embodiments, heat transferfluid may be used to transfer heat to a hydrotreating unit. The heattransfer fluid may pass through a heat exchange mechanism of thehydrotreating unit. Heat from the product stream may be transferred fromthe heat transfer fluid to the hydrotreating unit. Alternatively, atemperature of the heat transfer fluid may be increased with a heatingunit prior to processing the heat transfer fluid in a steam crackingunit or hydrotreating unit. In addition, heat of a heat transfer fluidmay be transferred to any other type of unit (e.g., distillation column,separator, regeneration unit for an activated carbon bed, etc.).

[2469] Heat from a heated formation may be recovered for use in heatinganother formation. FIG. 410 illustrates an embodiment of a heat transferfluid provided through injection well 606A into heated formation 2866.Heat may transfer from the heated formation to the heat transfer fluid.Heat source 508 may be used to control formation heat. The heat transferfluid may be produced from production well 512A. The heat transfer fluidmay be directed through injection well 606B to transfer heat from theheat transfer fluid to formation 2874. Formation conditions subsequentto an in situ conversion process may determine the heat transfer fluidtemperature. The heat transfer fluid may be produced from productionwell 512B. In some embodiments, formation 2874 may include U-tube wellsor closed casings with fluid insertion ports and fluid removal ports sothat heat transfer fluid does not enter into the rock of the formation.

[2470] Movement of the heat transfer fluid (e.g., product streams, inertgas, steam, and/or hydrocarbons) through the formation may be controlledsuch that any associated hydrocarbons in the formation are directedtowards the production wells. The formation heat and mass transfer ofthe heat transfer fluid may be controlled such that fluids within theformation are swept towards the production wells. During remediation ofa formation, the formation heat and mass transfer of the heat transferfluid may be controlled such that transfer of heat from the formation tothe heat transfer fluid is accomplished simultaneously with clean up ofthe formation.

[2471]FIG. 411 illustrates an in situ conversion process embodiment inwhich a heat transfer fluid is provided to formation 2876 throughinjection well 606. Heat within formation 2876 may be controlled by heatsource 508. The heat of the heat transfer fluid may be transferred tocooler formation 2878. The heat transfer fluid may be produced throughproduction well 512. In other embodiments, a heat transfer fluid may bedirected to a plurality of formations to heat the plurality offormations.

[2472]FIG. 412 illustrates an embodiment for controlling formation 2880to produce region of reaction 2882 in the formation. A region ofreaction may be any section of the formation having a temperaturesufficient for a reaction to occur. A region of reaction may be hotteror cooler than a portion of a formation proximate the region ofreaction. Material may be directed to the region of reaction throughinjection well 606. The material may be reacted within the region ofreaction. Any number and any type of heat source 508 may heat theformation and the region of reaction. Appropriate heat sources include,but are not limited to, electric heaters, surface burners, flamelessdistributed combustors, and/or natural distributed combustors. Theproduct may be produced through production well 512.

[2473] In some in situ conversion process embodiments, a region ofreaction may be heated by transference of heat from a heated product tothe region of reaction. In some embodiments, regions of reaction may bein series. A material may flow through the regions of reaction in aserial manner. The regions of reaction may have substantially the sameproperties. As such, flowing a material through such regions of reactionmay increase a residence time of the material in the regions ofreaction. Alternatively, the regions of reaction may have differentproperties (e.g., temperature, pressure, and hydrogen content). Flowinga material through such regions of reaction may include performingseveral different reactions with the material. Various materials may bereacted in a region of reaction. Examples of such materials include, butare not limited to, materials produced by an in situ conversion processand hydrocarbons produced from petroleum crude (e.g., tar, pitch,asphaltenes, heavy hydrocarbons, naphtha, methane, ethane, propane,and/or butane).

[2474] In some in situ conversion process embodiments, a region ofreaction may be formed by placing conduit 2884 in a heated portion offormation 2886. FIG. 413 depicts such an embodiment of an in situconversion process. A portion of conduit 2884 may be heated by theformation to form a region of reaction within the conduit. The conduitmay inhibit contact between the material and the formation. Theformation temperature and conduit temperature may be controlled by heatsource 508. Material may be provided through injection well 606. Thematerial may be produced through production well 512.

[2475] A shape of a conduit may be variable. For example, the conduitmay be curved, straight, or U-shaped (as shown in FIG. 414). U-shapedconduit 2888 may be placed within a heater well in a heated formation.Any number of materials may be reacted within the conduit. For example,water may be passed through a conduit such that the water is heated to atemperature higher than the initial water temperature. In otherembodiments, water may be heated in a conduit to produce steam. Materialmay be provided through injection site 2890 and produced throughproduction site 2892. The formation temperature may be controlled byheat source 508.

[2476] In some in situ conversion process embodiments, formations may beused to store materials. A first portion of a formation may be subjectedto in situ conversion. After in situ conversion, the first portion maybe permeable and have a large pore volume. Formation fluid (e.g.,pyrolysis fluid or synthesis gas) produced from another portion of theformation may be stored in the first portion. Alternately, the firstportion may be used to store a separated component of formation fluidproduced from the formation, a compressed gas (e.g., air), crude oil,water, or other fluid. Alternately, the first portion may be used tostore carbon dioxide or other fluid that is to be sequestered.

[2477] Materials may be stored in a portion of the formation temporarilyor for long periods of time. The materials may include inorganic and/ororganic compounds and may be in solid, liquid, and/or gaseous form. Ifthe materials are solids, the solid products may be stored as a liquidby dissolving the materials in a suitable solvent. If the materials areliquids or gases, they may be stored in such form. The materials may beproduced from the formation when needed. In some storage embodiments,the stored material may be removed from the formation by heating theformation using heat sources inserted in wellbores in the formation andproducing the stored material from production wells. The heat sourcesmay be heat sources used during a pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. The production wellsmay be production wells used during the pyrolysis and/or synthesis gasgeneration phase of the in situ conversion process. In otherembodiments, the heat source and/or production wells may be wells thatwere originally used for a different purpose and converted to a newpurpose. In some embodiments, some or all heat source and/or productionwells may be newly formed wells in the storage portion of the formation.

[2478] In a storage process embodiment, oil may be stored in a portionof a formation that has been subjected to an in situ conversion process.In some embodiments, natural gas may be stored in a portion of aformation that has been subjected to an in situ conversion process. Ifthe formation is close to the surface, the shallow depth of theformation may limit gas pressure. In certain embodiments, close spacingof wells may provide for rapid recovery of oil and/or natural gas withhigh efficiency.

[2479] In a storage process embodiment, compressed air may be stored ina portion of a formation that has been subjected to an in situconversion process. The stored compressed air may be used for peak powergeneration, load leveling, and/or to even out and compensate for thevariability of renewable power sources (e.g., solar and/or wind power).A portion of the stored compressed air may be used as an oxygen sourcefor a natural distributed combustor, flameless distributed combustor,and/or a surface burner.

[2480] In an in situ conversion process embodiment, water may beprovided to a hot formation to produce steam. The water may be appliedduring pyrolysis to help remove coke adjacent to or on heat sourcesand/or production wells. Water may also be introduced into the formationafter pyrolysis and/or synthesis gas generation is complete. Theproduced steam may sweep hydrocarbons towards production wells. Theformation heat transfer and mass transfer may be controlled to clean theformation during recovery of heat from the formation. The introducedwater may absorb heat from the formation as the water is transformed tosteam, resulting in cooling of the formation. The steam may be producedfrom the formation. Organic or other components in the steam may beseparated from the steam and/or water condensed from the steam. Thesteam may be used as a heat transfer fluid in a separation unit or inanother portion of the formation that is being heated. Cleaned orfiltered water may be produced along with subsequent cooling of theformation.

[2481] In an in situ conversion process embodiment, a hot formation maytreat water to remove dissolved cations (e.g., calcium and/or magnesiumions). The untreated water may be converted to steam in the formation.The steam may be produced and condensed to provide softened water (e.g.,water from which calcium and magnesium salts have been removed). Ifadditional water is provided to the formation, the retained salts in theformation may dissolve in the water and “hard” water may be produced.Therefore, order of treatment may be a factor in water purificationwithin a formation. A hot formation may sterilize introduced water bydestroying microbes.

[2482] In certain embodiments, a cooled formation may be used as a largeactivated carbon bed. After pyrolysis and/or synthesis gas generation atreated, cooled formation may be permeable and may include a significantweight percentage of char/coke. The formation may be substantiallyuniformly permeable without significant fluid passage fractures fromwellbore to wellbore within the formation. Contaminated water may beprovided to the cooled formation. The water may pass through the cooledformation to a production well. Material (e.g., hydrocarbons or metalcations) may be adsorbed onto carbon in the cooled formation, therebycleaning the water. In some embodiments, the formation may be used as afilter to remove microbes from the provided water. The filtrationcapability of the formation may depend upon the pore size distributionof the formation.

[2483] A treated portion of formation may be used to trap and filter outparticulates. Water with particulates may be introduced into a firstwellbore. Water may be produced from production wells. When theparticulate matter clogs the pore space adjacent to the first wellboresufficiently to inhibit further introduction of water with particulates,the water with particulates may be introduced into a different wellbore.A large number of wellbores in a formation subject to in situ treatmentmay provide an opportunity to purify a large volume of water and/orstore a large amount of particulate matter in a formation.

[2484] Water quality may be improved using a heated formation. Forexample, after pyrolysis (and/or synthesis gas generation) is completed,formation water that was inhibited from passing into the formationduring conversion by freeze wells or other types of barriers may beallowed to pass through the spent formation. The formation water may bepassed through a hot formation to form steam and soften the water (i.e.,ionic compounds are not present in significant amounts in the producedsteam). The steam produced from the formation may be condensed to formformation water. The formation water may be passed through a carbon bed(in a treatment facility or in a cooled, spent portion of the formation)to treat the formation water by adsorption, absorption, and/orfiltering.

[2485]FIG. 415 illustrates an embodiment for sequestering carbon dioxideas carbonate compounds in a portion of a formation. The carbon dioxidemay be sequestered in the formation by forming carbonate compounds fromthe carbon dioxide through carbonation reactions with pore water. Energyinput into heat sources 508 may be used to control a temperature of theheated portion of formation 2894. Valves may be used to control apressure of the heated portion of the formation. In other embodiments,carbon dioxide may be sequestered in a cooled formation by adsorbing thecarbon dioxide on carbon that remains in the formation.

[2486] In the embodiment depicted in FIG. 415, solution 2896 is providedto the lower portion of the formation through well 2898 into formation2894. The solution may be obtained, for example, from naturalgroundwater flow or from an aquifer in a deeper formation. In anembodiment, the solution may be seawater. In some embodiments, the saltcontent of the water may be concentrated by evaporation. In certainembodiments, the solution may be obtained from man-made industrialsolutions (e.g., slaked lime solution) or agricultural runoff. Thesolution may include sodium, magnesium, calcium, iron, manganese, and/orother dissolved ions. Furthermore, the solution may contact the ash fromthe spent formation as it is provided to the post treatment formation.Contact of the solution with the formation ash may produce a buffered,basic solution.

[2487] In some sequestration embodiments, carbon dioxide 1506 may beprovided to the upper portion of the formation through well 2900simultaneously with providing solution 2896 to the formation. Thesolution may be provided to the lower portion of the formation, suchthat the solution rises through a portion of the provided carbondioxide. Carbonate compounds may form in a dissolution zone at theinterface of the solution and the carbon dioxide. In certainembodiments, the carbonate compounds may form by the reaction of thebasic solution with the carbonic acid produced when the carbon dioxidedissolves in the solution. Other mechanisms, however, may also cause theformation and precipitation of the carbonate compounds.

[2488] The type of carbonate compounds formed may be determined by thedissolved ions in the solution. Examples of carbonate compounds include,but are not limited to, calcite (CaCO₃), magnesite (MgCO₃), siderite(FeCO₃), rhodochrosite (MnCO₃), ankerite (CaFe(CO₃)₂), dolomite(CaMg(CO₃)₂), ferroan dolomite, magnesium ankerite, nahcolite (NaHCO₃),dawsonite (NaAl(OH)₂CO₃), and/or mixtures thereof. Other carbonatecompounds that may be precipitated include, but are not limited to,cerussite (PbCO₃), malachite (Cu₂(OH)₂CO₃, azurite (Cu₃(OH)₂(CO₃)₂),smithsonite (ZnCO₃), witherite (BaCO₃), strontianite (SrCO₃), and/ormixtures thereof.

[2489] A portion of the solution may be slowly withdrawn from theformation to deposit carbonate compounds within the formation. Afterwithdrawal, the solution may be reinserted into the formation tocontinue precipitation of carbonate compounds in the formation. Thesolution may rise again through the provided carbon dioxide andadditional carbonates may be formed and precipitated. The solution maybe cycled up and down within the formation to maximize the precipitationof carbonates within the formation. The carbonate compounds may remainwithin the formation.

[2490] In an embodiment, chemical compounds (e.g., CaO) may be added tothe solution if the amount of ash remaining in the formation isinsufficient to provide adequate buffering. In some embodiments,chemical compounds may be added to surface water to produce a solution.

[2491] Altering the pH of a solution in which carbon dioxide isdissolved may allow carbonate formation. Compounds that hydrolyze indifferent temperature ranges to produce basic compounds may be includedin the solution. Therefore, altering the solution temperature may alterthe solution pH, thus allowing carbonate formation. Compounds thathydrolyze to produce basic compounds may include cyanates and nitrites.Examples of cyanates and nitrites may include, but are not limited to,potassium cyanate, sodium cyanate, sodium nitrite, potassium nitrite,and/or calcium nitrite. In some embodiments, urea may also hydrolyze toproduce a basic compound.

[2492] In a sequestration embodiment, carbon dioxide may be allowed todiffuse throughout a solution within a formation. The solution mayinclude at least one of the compounds that hydrolyze. The formation maybe heated such that the compound(s) included in the solution hydrolyzesand produces a basic solution. The carbonate compounds may precipitatewhen appropriate ions (e.g., calcium and/or magnesium) are present.Altering the solution temperature may provide an ability to alter theoccurrence and rate of carbonate precipitation in the formation. Heatmay be provided from heat sources in the formation.

[2493] In a sequestration embodiment, carbon dioxide may be provided toa dipping formation. A solution may be provided to the dipping formationso that the solution contacts carbon dioxide to allow for precipitationof carbonate in the formation. Carbon dioxide and/or solution additionmay be cycled to increase the amount of carbonate formed in theformation.

[2494] Formation of carbonate compounds may inhibit movement of mobileor released hydrocarbon compounds to groundwater. Formation of carbonatecompounds may decrease the permeability of the formation and inhibitwater or other fluid from migrating into or out of a portion of theformation in which carbonates have been formed. Formation of carbonatesmay decrease leaching of metals in the formation to groundwater,decrease formation deformation, and/or decrease well damage by providingsupport for the remaining formation overburden. In certain in situconversion process embodiments, the formation of carbonate compounds maybe a part of the abandonment and reclamation process for the formation.

[2495] In an embodiment, heating during in situ conversion processes maycause decomposition of calcite (limestone) or dolomite to lime andmagnesite. Upon carbonation, the calcite and dolomite may bereconstituted. The reconstitution may result in sequestration of asignificant volume of carbon dioxide.

[2496] In a sequestration embodiment, existing wellbores may be usedduring formation of carbonates in the formation. A solution may beprovided to the formation and recovery of the solution may be providedfrom adjacent or closely spaced wells to create small circulation cells.In some embodiments with a dipping or thick formation, a counterflow ofcarbon dioxide and water may be applied. The carbon dioxide may beprovided downdip (e.g., a point lower in the formation) and the solutionprovided updip (e.g., a point higher in the formation). The carbondioxide and the solution may migrate past each other in a counterflowmanner. In other embodiments, the carbon dioxide may be bubbled upthrough a solution-filled formation.

[2497] In a sequestration embodiment, precipitation of mineral phases(e.g., carbonates) may cement together the friable and unconsolidatedformation matrix remaining after an in situ conversion process. Incertain embodiments, the formation of minerals in an in situ formationmay be similar to natural mineral formation and cementation, thoughsignificantly accelerated.

[2498] In an embodiment, vertical and/or horizontal mineral formationnear a well may provide at least some well integrity. Mineralprecipitation may provide the formation around the well with highercohesiveness and strength. The increased cohesiveness and strength mayinhibit compaction and deformation of the formation around the wellbore.

[2499] In some in situ conversion process embodiments, non-hydrocarbonmaterials such as minerals, metals, and other economically viablematerials contained within the formation may be economically producedfrom the formation. In some embodiments, the non-hydrocarbon materialsmay be mined or extracted from the formation following an in situconversion process. However, mining or extracting material following anin situ conversion process may not be economically or environmentallyfavorable. In certain embodiments, non-hydrocarbon materials may berecovered and/or produced prior to, during, and/or after the in situconversion process for treating hydrocarbons using an additional in situprocess of treating the formation for producing the non-hydrocarbonmaterials.

[2500] In an embodiment for producing non-hydrocarbon material, aportion of the formation may be subjected to in situ conversion processto produce hydrocarbons and/or synthesis gas from the formation. Thetemperature of the portion may be reduced below the boiling point ofwater at formation conditions. A first fluid (e.g., extraction fluid)may be injected into the portion. The first fluid may be injectedthrough a production well, heater well, or injection well. The firstfluid may include an agent that reduces, mixes, combines, or forms asolution with non-hydrocarbon materials to be recovered. The first fluidmay be water, a basic solution, an acid solution, and/or a hydrocarbonfluid. In some embodiments, the first fluid may be introduced into theformation as a hot or warm liquid. The first fluid may be heated usingheat generated in another portion of the formation and/or using excessheat from another portion of the formation.

[2501] A second fluid may be produced in the formation from formationmaterial and the first fluid. The second fluid may be produced from theformation through production wells. The second fluid may include desirednon-hydrocarbon materials from the formation. The non-hydrocarbonmaterials may include valuable metals such as, but not limited to,aluminum, nickel, vanadium, and gold. The non-hydrocarbon materials mayalso include minerals that contain phosphorus, sodium, or magnesium. Incertain embodiments, the second fluid may include metals combined withminerals. For example, the second fluid may contain phosphates,carbonates, etc. Metals, minerals, or other non-hydrocarbon materialscontained within the second fluid may be produced or extracted from thesecond fluid.

[2502] Producing the non-hydrocarbon materials may include separatingthe materials from the solution mixture. Producing the non-hydrocarbonmaterials may include processing the second fluid in a treatmentfacility or refinery. In some embodiments, the first fluid may becirculated through the formation from an injection well to a removalsite of the second fluid. Any portion of the first fluid remaining inthe second fluid may be recirculated (or re-injected) into the formationas a portion of the first fluid. In other embodiments, the second fluidmay be treated at the surface to remove non-hydrocarbon materials fromthe second fluid. This may reconstitute the first fluid from the secondfluid. The reconstituted first fluid may be re-injected into theformation for further material recovery.

[2503] In certain embodiments (e.g., in a coal formation), a first fluidmay be injected into a portion of the formation that has been treatedusing an in situ conversion process. The first fluid may include water.The first fluid may break and/or fragment the formation into relativelysmall pieces of mineral matrix containing hydrocarbons. The relativelysmall pieces may combine with the first fluid to form a slurry. Theslurry may be removed or produced from the formation. The slurry may betreated in a treatment facility to separate the first fluid from therelatively small pieces of hydrocarbons. The mineral matrix containinghydrocarbon pieces may be treated in a refining or extraction process ina treatment facility. The mineral matrix containing hydrocarbon piecesmay be an anthracite form of coal.

[2504] In some embodiments, non-hydrocarbon materials may be producedfrom a formation prior to treating the formation in situ. Heat may beprovided to the formation from heat sources. The formation may reach anaverage temperature approaching below pyrolysis temperatures (e.g.,about 260° C. or less). A first fluid may be injected into theformation. The first fluid may dissolve and or entrain formationmaterial to form a second fluid. The second fluid may be produced fromthe formation.

[2505] Some hydrocarbon containing formations (such as oil shale) mayinclude nahcolite, trona, and/or dawsonite within the formation. Forexample, nahcolite may be contained in unleached portions of aformation. Unleached portions of a formation are parts of the formationwhere groundwater has not leached out minerals within the formation. Forexample, in the Piceance basin in Colorado, unleached oil shale is foundbelow a depth of about 500 m below grade. Deep unleached oil shaleformations in the Piceance basin center tend to be rich in hydrocarbons.For example, about 0.10 liters of oil per kilogram (L/kg) of oil shaleto about 0.15 L/kg of oil shale may be producible from an unleached oilshale formation.

[2506] Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, USA. Greater than about 5 weight %, and in some embodimentseven greater than about 10 weight %, or greater than about 20 weight %nahcolite may be present in a formation. Dawsonite is a mineral thatincludes sodium aluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite may bepresent in a formation at weight percents greater than about 2 weight %or, in some embodiments, greater than about 5 weight %. The nahcoliteand/or dawsonite may dissociate at temperatures used in an in situconversion process of treating a formation. The dissociation is stronglyendothermic and may produce large amounts of carbon dioxide. Thenahcolite and/or dawsonite may be solution mined prior to, during,and/or following treating a formation in situ to avoid the dissociationreactions. For example, hot water may be used to form a solution withnahcolite. Nahcolite may form sodium ions (Na⁺) and bicarbonate ions(HCO₃ ⁻) in aqueous solution. The solution may be produced from theformation through production wells.

[2507] A formation that includes nahcolite and/or dawsonite may betreated using an in situ conversion process. A perimeter barrier may beformed around the portion of the formation to be treated. The perimeterbarrier may inhibit migration of water into the treatment area. Duringan in situ conversion process, the perimeter barrier may inhibitmigration of dissolved minerals and formation fluid from the treatmentarea. During initial heating, a portion of the formation to be treatedmay be raised to a temperature below the disassociation temperature ofthe nahcolite. The first temperature may be less than about 90° C., orin some embodiments, less than about 80° C. The first temperature maybe, however, any temperature that increases a reaction of a solutionwith nahcolite, but is also below a temperature at which nahcolite maydissociate (above about 95° C. at atmospheric pressure). A first fluidmay be injected into the heated portion. The first fluid may includewater, steam, or other fluids that may form a solution with nahcoliteand/or dawsonite. The first fluid may be at an increased temperature(e.g., about 90° C. or about 100° C.). The increased temperature may besubstantially similar to the first temperature of the portion of theformation.

[2508] In some embodiments, the portion of the formation may be atambient temperature and the first fluid may be injected at an increasedtemperature. The increased temperature may be a temperature below aboiling point of the first fluid (e.g., about 90° C. for water).Providing the first fluid at an increased temperature may increase atemperature of a portion of the formation. Additional heat may beprovided from one or more heat sources (e.g., a heater in a heater well)placed in the formation.

[2509] In other embodiments, steam is included in the first fluid. Heatfrom the injection of steam into the formation may be used to provideheat to the formation. The steam may be produced from recovered heatfrom the formation (e.g., from steam recovered during remediation of aportion) or from heat exchange with formation fluids and/or withtreatment facilities.

[2510] A second fluid may be produced from the formation followinginjection of the first fluid into the formation. The second fluid mayinclude products of injection of the first fluid into the formation. Forexample, the second fluid may include carbonic acid or other hydratedcarbonate compounds formed from the dissolution of nahcolite in thefirst fluid. The second fluid may also include minerals and/or metals.The minerals and/or metals may include sodium, aluminum, phosphorus, andother elements. Producing the second fluid from the formation may reducean amount of carbon dioxide produced from the formation during an insitu conversion process. Reducing the amount of carbon dioxide may beadvantageous because the production of carbon dioxide from nahcolite isendothermic and uses significant amounts of energy. For example,nahcolite has a heat of decomposition of about 0.66 joules per kilogram(J/kg). The energy required to pyrolyze hydrocarbons in a formationusing an in situ process may generally be about 0.35 J/kg. Thus, todecompose nahcolite from a formation having about 20 weight % nahcolite,about 0.13 J/kg additional energy would be needed. Removing nahcolitefrom a formation using a solution mining process prior to treating theformation using an in situ conversion process may significantly reducecarbon dioxide emissions from the formation as well as energy requiredto heat the formation.

[2511] Some minerals (e.g., trona, pirssonite, or gaylussite) mayinclude associated water. Solution mining, or removing, such mineralsbefore heating the formation may reduce costs of heating the formationto pyrolysis temperatures since associated water is removed prior toheating of the formation. Thus, the heat for dissociation of water fromthe mineral does not have to be provided to the formation.

[2512]FIG. 416 depicts an embodiment for solution mining a formation.Barrier 2902 (e.g., a frozen barrier) may be formed around acircumference of treatment area 2862 of the formation. Barrier 2902 maybe any barrier formed to inhibit a flow of water into or out oftreatment area 2862. For example, barrier 2902 may include one or morefreeze wells that inhibit a flow of water through the barrier. In someembodiments, barrier 2902 has a diameter of about 18 m. Barrier 2902 maybe formed using one or more barrier wells 518. Barrier wells 518 mayhave a spacing of about 2.4 m. Formation of barrier 2902 may bemonitored using monitor wells 616 and/or by monitoring devices placed inbarrier wells 518.

[2513] Water inside treatment area 2862 may be pumped out of thetreatment area through production well 512. Water may be pumped until aproduction rate of water is low. Heat may be provided to treatment area2862 through heater wells 520. The provided heat may heat treatment area2862 to a temperature of about 90° C. or, in some embodiments, to atemperature of about 100° C., 110° C., or 120° C. A temperature oftreatment area 2862 may be monitored using temperature measurementdevices placed in temperature wells 2904.

[2514] A first fluid (e.g., water) may be injected through one or moreinjection wells 606. The first fluid may also be injected through aheater or production well located in the formation. The first fluid maymix and/or combine with non-hydrocarbon materials (e.g., minerals,metals, nahcolite, and dawsonite) that are soluble in the first fluid toproduce a second fluid. The second fluid, containing the non-hydrocarbonmaterials, may be removed from the treatment area through productionwell 512 and/or heater wells 520. Production well 512 and heater wells520 may be heated during removal of the second fluid. After producing amajority of the non-hydrocarbon materials from treatment area 2862,solution remaining within the treatment area may be removed (e.g., bypumping) from the treatment area through production well 512 and/orheater wells 520. A relatively high permeability treatment area 2862 maybe produced following removal of the non-hydrocarbon materials from thetreatment area.

[2515] Hydrocarbons within treatment area 2862 may be pyrolyzed and/orproduced using an in situ conversion process of treating a formationfollowing removal of the non-hydrocarbon materials. Heat may be providedto treatment area 2862 through heater wells 520. A mixture ofhydrocarbons may be produced from the formation through production well512 and/or heater wells 520.

[2516] In certain embodiments, during an initial heating up to atemperature near a boiling temperature of water, unleached solubleminerals within the formation may be disaggregated and dissolved inwater condensing within the formation. The water may be condensing incooler portions of the formation. Some of these minerals may flow in thecondensed water to production wells. The water and minerals are producedthrough the production wells.

[2517] Following an in situ conversion process, treatment area 2862 maybe cooled during heat recovery by introduction of water to produce steamfrom a hot portion of the formation. Introduction of water to producesteam may vaporize some hydrocarbons remaining in the formation. Watermay be injected through injection wells 606. The injected water may coolthe formation. The remaining hydrocarbons and generated steam may beproduced through production wells 512 and/or heater wells 520. Treatmentarea 2862 may be cooled to a temperature near the boiling point ofwater.

[2518] Treatment area 2862 may be further cooled to a temperature atwhich water will begin to condense within the formation (i.e., atemperature below a boiling temperature of water). Removing the water orother solvents from treatment area 2862 may also remove any materialsremaining in the treatment area that are soluble in water. The water maybe pumped out of treatment area 2862 through production well 512 and/orheater wells 520. Additional water and/or other solvents may be injectedinto treatment area 2862. This injection and removal of water may berepeated until a sufficient water quality within treatment area 2862 isreached. Water quality may be measured at injection wells 606, heaterwells 520, and/or production wells 512. The sufficient water quality maybe a water quality that substantially matches a water quality oftreatment area 2862 prior to treatment.

[2519] In some embodiments, treatment area 2862 may include a leachedzone located above an unleached zone. The leached zone may have beenleached naturally and/or by a separate leaching process. In certainembodiments, the unleached zone may be at a depth of about 500 m. Athickness of the unleached zone may be about 100 m to about 500 m.However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 2862 and a typeof formation. A first fluid may be injected into the unleached zonebelow the leached zone. Heat may also be provided into the unleachedzone.

[2520] In certain embodiments, a section of a formation may be leftunleached or without injection of a solution. The unleached section maybe proximate a selected section of the formation that has been leachedby providing a first fluid as described above. The unleached section mayinhibit the flow of water into the selected section. In someembodiments, more than one unleached section may be proximate a selectedsection.

[2521] In an embodiment, a formation may contain both nahcolite and/ordawsonite. For example, oil shale formations within the Green Riverlakebeds in the U.S. Piceance Basin contain nahcolite and dawsonite inaddition to kerogen. Nahcolite, hydrocarbons, and alumina (fromdawsonite) may be produced from these types of formations.

[2522] Water may be injected into the formation through a heater well oran injection well. The water may be heated and/or injected as steam. Thewater may be injected at a temperature at or near the decompositiontemperature of nahcolite. For example, the water may be at a temperatureof about 70° C., 90° C., 100° C., or 110° C. Nahcolite within theformation may form an aqueous solution following the injection of water.The aqueous solution may be removed from the formation through a heaterwell, injection well, or production well. Removing the nahcolite removesmaterial that would otherwise form carbon dioxide during heating of theformation to pyrolysis temperatures. Removing the nahcolite may alsoinhibit the endothermic dissociation of nahcolite during an in situconversion process. Removing the nahcolite may reduce mass within theformation and increase a permeability of the formation. Reducing themass within the formation may reduce the heat required to heat totemperatures needed for the in situ conversion process. Reducing themass within the formation may also increase a speed at which a heatfront within the formation moves. Increasing the speed of the heat frontmay reduce a time needed for production to begin. In some embodiments,slightly higher temperatures may be used in the formation (e.g., aboveabout 120° C.) and the nahcolite may begin to decompose. In such a case,nahcolite may be removed from the formation as a soda ash (Na₂CO₃).

[2523] Nahcolite removed from the formation may be heated in a treatmentfacility to form sodium carbonate and/or sodium carbonate brine. Heatingnahcolite will form sodium carbonate according to the equation:

2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (79)

[2524] The sodium carbonate brine may be used to solution mine alumina.The carbon dioxide produced may be used to precipitate alumina. If sodaash is produced from solution mining of nahcolite, the soda ash may betransported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

[2525] Following removal of nahcolite from the formation, the formationmay be treated using an in situ conversion process to producehydrocarbon fluids from the formation. Remaining water is drained fromthe solution mining area through dewatering wells prior to heating to insitu conversion process temperatures. During the in situ conversionprocess, a portion of the dawsonite within the formation may decompose.Dawsonite will typically decompose at temperatures above about 270° C.according to the reaction:

2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (80)

[2526] The alumina formed from EQN. 80 will tend to be in the form ofchi alumina. Chi alumina is relatively soluble in basic fluids.

[2527] Alumina within the formation may be solution mined using arelatively basic fluid following reaching pyrolysis temperatures ofhydrocarbons within the formation. For example, a dilute sodiumcarbonate brine, such as 0.5 Normal Na₂CO₃, may be used to solution minealumina. The sodium carbonate brine may be obtained from solution miningthe nahcolite. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may form analumina solution that may be removed from the formation. The aluminasolution may be removed through a heater well, injection well, orproduction well. An excess of basic fluid may have to be maintainedthroughout an alumina solution mining process.

[2528] Alumina may be extracted from the alumina solution in a treatmentfacility. In an embodiment, carbon dioxide may be bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from the in situ conversion process or fromdecomposition of the dawsonite during the in situ conversion process.

[2529] In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (e.g., greaterthan about 20 weight %) in a depocenter of the formation. The depocentermay contain only about 5 weight % or less dawsonite on average. However,in bottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce a fluid cost,heating cost, and/or equipment cost associated with operating a solutionmining process.

[2530] Nordstrandite (Al(OH)₃) is another aluminum bearing mineral thatmay be found in a formation. Nordstrandite decomposes at about the sametemperatures (about 300° C.) as dawsonite and will produce aluminaaccording to the equation:

2Al(OH)₃→Al₂O₃+3H₂O.  (81)

[2531] Nordstrandite is typically found in formations that also containdawsonite and may be solution mined simultaneously with the dawsonite.

[2532] Solution mining dawsonite and nahcolite may be a simple processthat produces only aluminum and soda ash from a formation. It may bepossible to use some or all hydrocarbons produced from an in situconversion process to produce direct current (DC) electricity on a siteof the formation. The produced DC electricity may be used on the site toproduce aluminum metal from the alumina using the Hall process. Aluminummetal may be produced from the alumina by melting the alumina in atreatment facility on the site. Generating the DC electricity at thesite may save on costs associated with using hydrotreaters, pipelines,or other treatment facilities associated with transporting and/ortreating hydrocarbons produced from the formation using the in situconversion process.

[2533] Some formations may also contain amounts of trona. Trona is asodium sesquicarbonate (Na₂CO₃.NaHCO₃.2H₂O) that has properties andundergoes reactions (including decomposition) very similar to those ofnahcolite. Treatments for solution mining of trona may be substantiallysimilar to treatments used for solution mining of nahcolite. Trona maytypically be found in kerogen formations such as oil shale formations inWyoming.

[2534] For certain types of formations, solution mining may be used torecover non-hydrocarbon materials prior to heating the formation tohydrocarbon pyrolysis temperatures. Examples of such materials andformations may include nahcolite and dawsonite in Green River oil shale,trona in Wyoming oil shale, or ammonia from buddingtonite in the Condordeposit in Queensland, Australia. Other non-hydrocarbon materials thatmay be solution mined include carbonates (e.g., trona, eitelite,burbankite, shortite, pirssonite, gaylussite, norsethite,thermonatrite), phosphates, carbonate-phosphates (e.g., bradleyite),carbonate chlorides (e.g., northupite), silicates (e.g., albite,analcite, sepiolite, loughlinite, labuntsovite, acmite, elpidite,magnesioriebeckite, feldspar), borosilicates (e.g., reedmergnerite,searlesite, leucosphenite), and halides (e.g., neighborite, cryolite,halite). Solution mining prior to hydrocarbon pyrolysis may increase apermeability of the formation and/or improve other features (e.g.,porosity) of the formation for the in situ process. Solution mining mayalso remove significant portions of compounds that will tend toendothermically dissociate at increased temperatures. Removing theseendothermically dissociating compounds from the formation tends todecrease an amount of heat input required to heat the formation.

[2535] For some types of formations, it may be advantageous to solutionmine a formation after pyrolysis and/or synthesis gas production. Manydifferent types of non-hydrocarbon materials may be removed from aformation following an in situ conversion process.

[2536] For example, phosphate may be removed from marine oil shaleformations such as the Phosphoria formation in Idaho. Phosphate may havea weight percentage up to about 20 weight % or about 30 weight % inthese formations. Recovered phosphate may be used in combination withammonia and/or sulfur produced during the in situ conversion process toproduce useable materials such as fertilizer.

[2537] Metals may also be recoverable from marine oil shale deposits.Metals such as uranium, chromium, cobalt, nickel, gold, zinc, etc. maybe recovered from marine oil shale formations. Metals may also be foundin certain bitumen deposits. For example, bitumen deposits may containamounts of vanadium, nickel, uranium, platinum, or gold.

[2538] A simulation was used to predict the effects of solution miningnahcolite and dawsonite from an oil shale formation. The simulationpredicts the effect on oil production and energy requirements forproducing hydrocarbons from the oil shale formation using an in situconversion process. The kinetics of decomposition of nahcolite anddawsonite were used in the simulation.

[2539] Nahcolite decomposed into soda ash, carbon dioxide, and water.The frequency factor for the decomposition was 7.83×10¹⁵ (L/days). Theactivation energy was 1.015×10⁵ joules per gram mole (J/gmol). The heatof reaction was −62,072 J/gmol.

[2540] Dawsonite decomposed into soda ash plus alumina (Al₂O₃), carbondioxide, and water. The frequency factor for the decomposition was1.0×10²⁰ (L/days). The activation energy was 2.039×10⁵ J/gmol. The heatof reaction was −151,084 J/gmol.

[2541] The simulation assumed a 12.2 m well spacing in a triangularpattern. An injector well to producer well ratio was 12 to 1. FIG. 417illustrates cumulative oil production (m³) and cumulative heat input(kilojoules) versus time (years) using an in situ conversion process forsolution mined oil shale and for non-solution mined oil shale. Curve2906 illustrates cumulative oil production for non-solution mined oilshale. Curve 2908 illustrates cumulative heat input for non-solutionmined oil shale. Curve 2910 illustrates cumulative oil shale productionfor solution mined oil shale. Curve 2912 illustrates cumulative heatinput for solution mined oil shale.

[2542] The non-solution mined oil shale was assumed to have a 0.125liters per kilogram (L/kg) Fischer Assay with 5% dawsonite and 20%nahcolite, a 1.9% fracture porosity, and a 65% water saturation. Thesolution mined oil shale was found to have a 0.125 L/kg Fischer Assaywith 5% dawsonite and 0% nahcolite, a 29% porosity (created from removalof the nahcolite), and a 1.5% water saturation. The solution mined oilshale was assumed to have a relatively high permeability, which reducesthe water saturation to 1.5%.

[2543] As shown in FIG. 417, the simulation predicts that oil productionin solution mined oil shale (curve 2910) begins sooner and is fasterthan oil production in the non-solution mined oil shale (curve 2906).For example, after about 9 years, solution mined oil shale has producedabout 9500 m³ of oil, while non-solution mined oil shale has onlyproduced about 1500 m³ of oil. Non-solution mined oil shale will produceabout 9500 m³ of oil in about 12 years, 3 years later than solutionmined oil shale.

[2544] Also, the simulation predicts that less heat is needed to produceoil from solution mined oil shale (curve 2912) than from non-solutionmined oil shale (curve 2908). For example, after about 9 years, solutionmined oil shale has required about 9×10¹⁰ kJ of heat input, whilenon-solution mined oil shale has required about 1.1×10¹¹ kJ of heatinput.

[2545] In certain embodiments a soluble compound (e.g., phosphates,bicarbonates, alumina, metals, minerals, etc.) may be produced from asoluble compound containing formation (e.g., a formation that containsnahcolite, dawsonite, nordstrandite, trona, carbonates,carbonate-phosphates, carbonate chlorides, silicates, borosililcates,etc.) that is different from a hydrocarbon containing formation. Forexample, the soluble compound containing formation may be adjacent(e.g., lower or higher than) the hydrocarbon containing-formation, or atdifferent non-adjacent depths than the hydrocarbon containing formation.In other embodiments, the soluble compound containing formation may belocated at a different geographic location than the hydrocarboncontaining formation.

[2546] In an embodiment, heat is provided from one or more heat sourcesto at least a portion of a hydrocarbon containing formation. A mixture,at some point, may be produced from the formation. The mixture mayinclude hydrocarbons from the formation as well as other compounds suchas CO₂, H₂, etc. Heat from the formation, or heat from the mixtureproduced from the formation, may be used to adjust or change a qualityof a first fluid that is provided to the soluble compound containingformation. Heat may be provided in the form of hot water or steamproduced from the formation. In other embodiments, heat may betransferred by heat exchange units to the first fluid. In otherembodiments, a heated portion or component from the mixture may be mixedwith the first fluid to heat the fluid.

[2547] Alternately, or in addition, a component from the mixtureproduced from the hydrocarbon containing formation may be used to adjusta quality of a first fluid. For example, acidic compounds (e.g.,carbonic acid, organic acids) or basic compounds (e.g., ammonium,carbonate, or hydroxide compounds) from the mixture produced from thehydrocarbon containing formation may be used to adjust the pH of thefirst fluid. For example, CO₂ from the hydrocarbon containing formationmay be used with water to acidify the first fluid. In certainembodiments, components added to the first fluid (e.g., divalentcations, pyridines, or organic acids such as carboxylic acids ornaphthenic acids) may increase the solubility of the soluble compound inthe first fluid.

[2548] Once adjusted (e.g., heated and/or changed by having at least onecomponent added to the first fluid), the first fluid may be injectedinto the soluble compound containing formation. The first fluid may, insome embodiments, include hot water or steam. The first fluid mayinteract with the soluble compound. The soluble compound may at leastpartially dissolve. A second fluid including the soluble compound may beproduced from the soluble compound containing formation. The solublecompound may be separated from the second fluid stream and treated orprocessed. Portions of the second fluid may be recycled into theformation.

[2549] In certain embodiments, heat from the hydrocarbon containingformation may migrate and heat at least a portion of the solublecompound containing formation. In some embodiments, the soluble compoundcontaining formation may be-substantially near, adjacent to, orintermixed with the hydrocarbon containing formation. The heat thatmigrates may be useful to enhance the solubility of the soluble compoundwhen the first fluid is applied to the soluble compound containingformation. Heat that migrates from the hydrocarbon containing formationmay be recovered instead of being lost.

[2550] Reusing openings (wellbores) for different applications may becost effective in certain embodiments. In some embodiments, openingsused for providing the heat sources (or from producing from thehydrocarbon containing formation) may be used to provide the first fluidto the soluble compound containing formation or to produce the secondfluid from the soluble compound containing formation.

[2551] In certain embodiments, a solution may be first provided to, orproduced from, a formation in a solution mining operation. The solutionmay be provided or produced through openings. One or more of the sameopenings may later be used as heater wells or producer wells for an insitu conversion process. Additionally, one or more of the same openingsmay be used again for providing a first fluid to the same formationlayer or to a different formation layer. For example, the openings maybe used to solution mine components such as nahcolite. These openingsmay further be used as heater wells or producer wells in the hydrocarboncontaining formation. Then the openings may be used to provide the firstfluid to either the hydrocarbon containing layer or a different layer ata different depth than the hydrocarbon containing layer. These openingsmay also be used when producing a second fluid from the soluble compoundcontaining formation.

[2552] Hydrocarbon containing formations may have varied geometries andshapes. Conventional extraction techniques may not be appropriate forall formations. In some formations, rich hydrocarbon containing materialmay be positioned in layers that are too thin to be economicallyextracted using conventional methods. The rich hydrocarbon containingformations typically occur in beds having thicknesses between about 0.2m and about 8 m. These rich hydrocarbon containing formations mayinclude, but are not limited to, sapropelic coals (boghead, cannelcoals, and/or torbanites), as well as kukersites, tasmanites, andsimilar high quality oil shales. The hydrocarbon layers may yield fromabout 205 liters of oil per metric ton to about 1670 liters of oil permetric ton upon pyrolysis.

[2553]FIGS. 380 and 381 depict representations of embodiments of in situconversion process systems that may be used to produce a thin richhydrocarbon layer. To produce such layers, directionally drilled wellsmay be used to heat the thin hydrocarbon layer within the formation,plus a minimum amount of rock above and/or below. In some embodiments,the heat source wells may be placed in the rock above and/or below thethin hydrocarbon layer. The wells may be closely spaced to reduce heatlosses and speed the heating process. In addition, drilling technologiessuch as geosteering, slim well, coiled tubing, and other techniques maybe utilized to accurately and economically place the wells. Conductiveheat losses to the surrounding formation may be offset by a high oilcontent of the thin hydrocarbon layer, rapid heating of the thinhydrocarbon layer (e.g., a heating rate in the range of about 1° C./dayto about 15° C./day), and/or close spacing (meter scale) of heaters.Subsidence may be reduced, or even minimized, by positioning heaterwells in a non-hydrocarbon and/or lean section of the formationimmediately beneath and/or at the base of the thin hydrocarbon layer. Anon-hydrocarbon and/or lean section of the formation may lose lessmaterial than the thin hydrocarbon layer. Therefore, the structuralintegrity of formation may be maintained.

[2554] In some in situ conversion process embodiments, formations may betreated in situ by heating with a heat transfer fluid. A method fortreating a formation may include injecting a heat transfer fluid intothe formation. In some embodiments, steam may be used as the heattransfer fluid. The heat from the heat transfer fluid may transfer to aselected section of the formation. In conjunction with heat from heatsources, the heat may pyrolyze at least some of the hydrocarbons withinthe selected section of the formation. A vapor mixture that includespyrolysis products may be produced from the formation. The pyrolysisproducts may include hydrocarbons having an average API gravity of atleast about 25°. The vapor mixture may also include steam.

[2555] In one embodiment, hydrocarbons may be distilled from theformation. For example, hydrocarbons may be separated from the formationby steam distillation. The heat from the heat transfer fluid (e.g.,steam), and/or heat from heat sources, may vaporize some of thehydrocarbons within the selected section of the formation. The vaporizedhydrocarbons may include hydrocarbons having a carbon number greaterthan about 1 and a carbon number less than about 8. The vapor mixturemay include the vaporized hydrocarbons. For example, in a heavyhydrocarbon containing formation, pyrolyzation fluids and steam maydistill a substantial portion of unconverted heavy hydrocarbons. Inaddition, coke, sulfur, nitrogen, oxygen, and/or metals may be separatedfrom formation fluid in the formation.

[2556] It may be advantageous to use steam injection for in situtreatment of heavy hydrocarbon or bitumen containing formations. In anembodiment, steam injection and soaking with steam may be applied to oilshale formations, coal formations, and hydrocarbon containing formationsthat have sufficiently high permeability and homogeneity. Substantiallyuniform heating of a substantial portion of the hydrocarbons in aformation to pyrolysis temperatures with heat transfer from steam andheat sources (e.g., electric heaters, gas burners, natural distributedcombustors, etc.) may be enhanced if the formation has relatively highpermeability and homogeneity. Relatively high permeability andhomogeneity may allow the injected steam to contact a large surface areawithin the formation.

[2557] In certain embodiments, in situ treatment of hydrocarbons may beaccomplished with a suitable combination of steam pressure, temperature,and residence time of injected steam, together with a selected amount ofheat from heat sources, at a selected depth in the formation. Forexample, at a temperature of about 350° C., at hydrostatic pressure, andat a depth of about 700 m to about 1000 m, a residence time of at leastapproximately one month may be required for in situ steam treatment ofhydrocarbons with steam and heat sources.

[2558] In some embodiments, relatively deep formations may beparticularly suitable for in situ treatment with heat sources and steaminjection. Higher steam pressures and temperatures may be readilymaintained in relatively deep formations. Furthermore, steam may be ator approaching supercritical conditions below a particular depth.Supercritical steam or near supercritical steam may facilitatepyrolyzation of hydrocarbons. In other embodiments, in situ treatment ofa relatively shallow formation may be performed with a sufficient amountof overpressure (e.g., an overpressure above a hydrostatic pressure).The amount of overpressure may depend on the strength of the formationor the overburden of the formation.

[2559] In an embodiment, in situ treatment of a formation may includeheating a selected section of the formation with one or more heatsources, and one or more cycles of steam injection. The cycles of steammay soak the formation with steam for a selected time period. Theselected time period may be about one month. In other embodiments, theselected time period may be about one month to about six months. Theselected section may be heated to a temperature between about 275° C.and about 350° C. In another embodiment, the formation may be heated toa temperature of about 350° C. to about 400° C. A vapor mixture, whichmay include pyrolyzation fluids, may be produced from the formationthrough one or more production wells placed in the formation.

[2560] In certain embodiments, in situ treatment of a formation mayinclude continuous steam injection into the formation, together withaddition of heat from heat sources. Pyrolyzation fluids may be producedfrom different portions of the formation during such treatment.

[2561]FIG. 419 illustrates a schematic of an embodiment of continuousproduction of a vapor mixture from a formation. FIG. 419 includesformation 2914 with heat transfer fluid injection well 606 and well2915. The wells may be members of a larger pattern of wells placedthroughout the formation. A portion of a formation may be heated topyrolyzation temperatures by heating the formation with heat sources andan injected heat transfer fluid. Heat transfer fluid 2916, such assteam, may be injected through injection well 606. Other wells may beused to provide the steam. Injected heat transfer fluid may be at atemperature between about 300° C. and about 500° C. In an embodiment,heat transfer fluid 2916 is steam.

[2562] Heat transfer fluid 2916, and heating from the heat sources, mayheat region 2918 of the formation between wells 606 and 2915. Suchheating may heat region 2918 into a selected temperature range (e.g.,between about 275° C. and about 400° C.). An advantage of a continuousproduction method may be that the temperature across region 2918 may besubstantially uniform and substantially constant with time once theformation has reached substantial thermal equilibrium. Vapor mixture2920 may exit continuously through well 2915. Vapor mixture 2920 mayinclude pyrolysis fluids and/or steam. In one embodiment, vapor mixture2920 may be fed to surface separation unit 2922. Separation unit 2922may separate vapor mixture 2920 into stream 2924 and hydrocarbons 594.Stream 2924 may be composed primarily of steam or water. Stream 2924 maybe re-injected into the formation. Hydrocarbons may include pyrolysisfluids and hydrocarbons distilled from the formation.

[2563] In an embodiment, production of a vapor mixture from a formationmay be performed in a batch mode. Injection of the heat transfer fluidmay continue for a period of time, together with heat from one or moreheat sources. In an embodiment, heat from the heat sources may combinewith heat from transfer fluid until the temperature of a portion of theformation is at a desired temperature (e.g., between about 275° C. andabout 400° C.). Higher or lower temperatures may also be used.Alternatively, injection may continue until a pore volume of the portionof the formation is substantially filled. After a selected period oftime subsequent to ceasing injection of the heat transfer fluid, vapormixture 2920 may be produced from the formation through wellbore 2915.The vapor mixture may include pyrolysis fluids and/or steam. In someembodiments, the vapor mixture may exit through injection well 606. Inan embodiment, the selected period of time may be about one month.

[2564] Injected steam may contact a substantial portion of a volume ofthe formation to be treated. The heat transfer fluid may be injectedthrough one or more injection wells. Similarly, the heat sources may beplaced in one or more heater wells. The injection wells may be locatedsubstantially horizontally in the formation. Alternatively, theinjection wells may be disposed substantially vertically or at anydesired angle (e.g., along dip of the formation). The heat transferfluid may be injected into regions of relatively high water saturation.Relatively high water saturation may include water concentrationsgreater than about 50 volume percent. In some embodiments, the averagespacing between injection wells may be between about 40 m and about 50m. In other embodiments, the average spacing may be between about 50 mand about 60 m.

[2565] In an embodiment, the heat from injection of a heat transferfluid, together with heat from one or more heat sources, may pyrolyze atleast some of the hydrocarbons in the selected first section. In certainembodiments, the heat may mobilize at least some of the hydrocarbonswithin the selected first section. Injection of a heat transfer fluid,and/or heat from the heat sources, may decrease a viscosity ofhydrocarbons in the formation. Decreasing the viscosity of thehydrocarbons may allow the hydrocarbons to be more mobile. In addition,some of the heat may partially upgrade a portion of the hydrocarbons.Partial upgrading may reduce the viscosity and/or mobilize thehydrocarbons. Some of the mobilized hydrocarbons may flow (e.g., due togravity) from the selected first section of the formation to a selectedsecond section of the formation. Heat from the heat transfer fluid andthe heat sources may pyrolyze at least some of the mobilized fluids inthe selected second section.

[2566] In some embodiments, heat may be provided from one or more heatsources to at least one portion of the formation. The one or more heatsources may include electric heaters, flameless distributed combustors,or natural distributed combustors. Heat from the heat sources maytransfer to the selected first section and the selected second sectionof the formation. The heat may heat or superheat steam injected into theformation. The heat may also vaporize water in the formation to generatesteam. In addition, the heat from the heat sources may mobilize and/orpyrolyze hydrocarbons in the selected first section and/or the selectedsecond section of the formation.

[2567] In an embodiment, the selected first section and the selectedsecond section may be located in a relatively deep portion of theformation. For example, a relatively deep portion of a formation may bebetween about 100 m and about 300 m below the surface. Heat from theheat sources and the heat transfer fluid may pyrolyze at least some ofthe hydrocarbons within the selected second section of the formation. Insome embodiments, at least about 20 percent of the hydrocarbons in theformation may be pyrolyzed. The pyrolyzed hydrocarbons may have anaverage API gravity of at least about 25°.

[2568] In an embodiment, a vapor mixture may be produced from theformation. The vapor mixture may contain pyrolyzed fluids. In otherembodiments, the vapor mixture may contain pyrolyzed fluids and/or heattransfer fluid. The vapor mixture may include hydrocarbons distilledfrom the formation. The heat transfer fluid may be separated from thepyrolyzed fluids and distilled hydrocarbons at the surface of theformation. For example, heat transfer fluid may be separated using amembrane separation method. Alternatively, heat transfer fluid may beseparated from pyrolyzed fluids and distilled hydrocarbons in theformation. The pyrolyzed fluids and distilled hydrocarbons may then beproduced from the formation.

[2569] In an embodiment, the vapor mixture may be produced from theselected second section of the formation. Alternatively, the vapormixture may be produced from the selected first section.

[2570] In one embodiment, the mobilized fluids may be partially upgradedin the selected second section. The partially upgraded fluids may beproduced from the formation and re-injected back into the formation.

[2571] In certain embodiments, the vapor mixture may be produced throughone or more production wells. In some embodiments, at least some of thevapor mixture may be produced through a heat source wellbore.

[2572] In one embodiment, a liquid mixture composed primarily ofcondensed heat transfer fluid may accumulate in a portion of theformation. The liquid mixture may be produced from the formation. Theliquid mixture may include liquid hydrocarbons. The condensed heattransfer fluid may be separated from the liquid hydrocarbons in theformation and the condensed heat transfer fluid may be produced from theformation. Alternatively, the liquid mixture may be produced from theformation and fed to a separation unit. The separation unit may separatethe condensed heat transfer fluid from the liquid hydrocarbons. Theliquid hydrocarbons may then be re-injected into the formation.

[2573]FIG. 420 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection. Portion2926 of the formation may be treated with steam injection. Portion 2928may be untreated. Horizontal injection and/or heat source wells 2930 maybe located in an upper or selected first section of portion 2926.Horizontal production wells 2932 may be located in a lower or selectedsecond section of portion 2926. The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[2574] Steam may be injected into the formation through wells 2930,and/or heat sources may be placed in such wells 2930 and provide heat tothe formation and/or to the steam. The heat from the steam and the heatsources may heat the selected first and second sections to pyrolyzationtemperatures and pyrolyze some of the hydrocarbons in the sections. Inaddition, heat from the steam injection and the heat sources maymobilize some hydrocarbons in the sections. The mobilized hydrocarbonsin the selected first section may flow (e.g., by gravity and or flowtowards low pressure of a pressure gradient established by productionwells) to the selected second section as indicated by arrows 2934. Someof the mobilized hydrocarbons may be pyrolyzed in the selected secondsection. Pyrolyzed fluids and/or mobilized fluids may be producedthrough production wells 2932. In an embodiment, condensed fluids (e.g.,condensed steam) may be produced through production wells in theselected second section.

[2575]FIG. 421 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with steam injection and heatsources. Portion 2936 of the formation may be treated with heat fromheat sources and steam injection. Portion 2938 may be untreated. Portion2936 may include a horizontal heat source and/or injection well 606located in an upper or selected first section. Horizontal productionwell 2932 may be located above the injection well in the selected firstsection of portion 2936. The production well and/or the injection wellmay include a heat source. Water and oil production well 2940 may beplaced in the selected second section of the formation. The wells may bemembers of a larger pattern of wells placed throughout a portion of theformation.

[2576] Heat and/or steam may be provided to the formation through well606. Such heat and steam may heat the selected first and second sectionsto pyrolyzation temperatures. Hydrocarbons may be pyrolyzed in theselected first section between well 2932 and well 606. In addition, theheat may mobilize some hydrocarbons in the sections. The mobilizedhydrocarbons in the selected first section may flow through region 2942to the selected second section as indicated by arrows 2944. Some of themobilized hydrocarbons may be pyrolyzed in the selected second section.Pyrolyzed fluids and/or mobilized fluids may be produced throughproduction well 2932. In addition, condensed fluids (e.g., steam) may beproduced through production well 2940 in the selected second section.

[2577] In one embodiment, a method of treating a hydrocarbon containingformation in situ may include heating the formation with heat sources,and also injecting a heat transfer fluid into a formation and allowingthe heat transfer fluid to flow through the formation. Heat transferfluid may be injected into the formation through one or more injectionwells. The injection wells may be located substantially horizontally inthe formation. Alternatively, the injection wells may be disposedsubstantially vertically in the formation or at a desired angle. Thesize of a selected section of the formation may increase as a heattransfer fluid front migrates through the formation. “Heat transferfluid front” is a moving boundary between the portion of the formationtreated by heat transfer fluid and the portion untreated by heattransfer fluid. The selected section may be a portion of the formationtreated or contacted by the heat transfer fluid. Heat from the heattransfer fluid, together with heat from one or more heat sources, maypyrolyze at least some of the hydrocarbons within the selected sectionof the formation. In an embodiment, the average temperature of theselected section may be about 300° C., which corresponds to a heattransfer fluid pressure of about 90 bars.

[2578] In some embodiments, heat from the heat transfer fluid and/or oneor more heat sources may mobilize at least some of the hydrocarbons atthe heat transfer fluid front. The mobilized hydrocarbons may flowsubstantially parallel to the heat transfer fluid front. Heat from theheat transfer fluid, in conjunction with heat from the heat sources, maypyrolyze at least some of the hydrocarbons in the mobilized fluid.

[2579] In an embodiment, a vapor mixture may migrate to an upper portionof the formation. The vapor mixture may include pyrolysis fluids. Thevapor mixture may also include heat transfer fluid and/or distilledhydrocarbons. In an embodiment, the vapor mixture may be produced froman upper portion of the formation. The vapor mixture may be producedthrough one or more production wells located substantially horizontallyin the formation.

[2580] In one embodiment, a portion of the heat transfer fluid maycondense and flow to a lower portion of the selected section. A portionof the condensed heat transfer fluid may be produced from a lowerportion of the selected section. The condensed heat transfer fluid maybe produced through one or more production wells. Production wells maybe located substantially horizontally in the formation.

[2581]FIG. 422 illustrates a cross-sectional representation of anembodiment of an in situ treatment process with heat sources and steaminjection. Portion 2946 of the formation may be treated with heatsources and steam injection. Portion 2948 may be untreated. Portion 2946may include horizontal heat source and/or injection well 606B.Alternatively or in addition, portion 2946 may include vertical heatsource and/or injection well 606A. Horizontal production well 2932 maybe located in an upper portion of the formation. Portion 2946 may alsoinclude condensed fluid production well 512 (production well 512 maycontain one or more heat sources). The wells may be members of a largerpattern of wells placed throughout a portion of the formation.

[2582] Heat and/or steam may be provided into the formation throughwells 606B or 606A. The heat and/or steam may flow through the formationin the direction indicated by arrows 2950. A size of a section treatedby the heat and/or steam (i.e., a selected section) increases as theheat and/or steam flows through the untreated portion of the formation.The formation may include migrating heat and/or steam front 2952 at aboundary between portion 2946 and portion 2948.

[2583] Mobilized fluids may flow in the direction of arrows 2954 towardproduction well 2932. Fluids may be pyrolyzed and produced throughproduction well 2932. Steam and distilled hydrocarbons may also beproduced through well 2932. In addition, condensed fluids may flowdownward in the direction of arrows 2956. The condensed fluids may beproduced through production well 512. The heat source in production well512 may pyrolyze some of the produced hydrocarbons.

[2584] Heat form the heat sources and/or steam may mobilize somehydrocarbons at the migrating steam front. The mobilized hydrocarbonsmay flow downward in a direction substantially parallel to the front asindicated by arrow 2958. A portion of the mobilized hydrocarbons may bepyrolyzed. At least some of the mobilized hydrocarbons may be producedthrough production well 2932 or production well 512.

[2585] In certain embodiments, existing steam treatmentprocesses/systems may be enhanced by the addition of one or more heatsources to the process/system. Heat sources may be placed in locationssuch that heat from the heat source openings will heat areas of theformation that are not heated (or that are less heated) by the steam.For example, if the steam is preferentially flowing in certain pathwaysthrough the formation, the heat sources may be placed in locations thatheat areas of the formation that are less heated by steam in thesepathways. In some embodiments, hydrocarbon fluids may be producedthrough a heel portion of a wellbore of a heat source. The heel portionof the heat source may be at a lower temperature than the toe portion ofthe heat source. Efficiency and production of hydrocarbons from a steamflood may be enhanced.

[2586] Some hydrocarbon containing formations may contain a significantportion of adsorbed and/or absorbed methane. For example, some coal bedscontain a significant amount of adsorbed methane. Often such methane ispresent in coal formations with a cleat system saturated with formationwater. The formation may be in a water recharge zone. Only a smallportion of the methane may be produced from hydrocarbon containingformations without removing the formation water. In some cases theinflow of water is so large that the hydrocarbon containing materialcannot be dewatered effectively. The removal of the formation water mayreduce pressure in the hydrocarbon containing formation and cause therelease of some adsorbed methane. The removal of formation water mayreduce pressure in the hydrocarbon containing formation and cause therelease of some adsorbed methane. In some embodiments, the dewateringprocess may result in recovery of up to about 30% of adsorbed methanefrom a portion of the formation. In some embodiments, carbon dioxide maybe injected into a formation to further enhance recovery of methane. Incertain embodiments, heating an oil shale formation may cause thermaldesorption of gas from a portion of the oil shale formation.

[2587] Increasing the average temperature of a formation with entrainedmethane may increase the yield of methane from the formation.Substantial recovery of entrained methane may be achieved at atemperature at or above approximately the boiling point of water in theformation. During heating, substantially all free moisture may beremoved from a portion of the formation after the portion has reached anaverage temperature of about the ambient boiling point of water.

[2588] In certain embodiments, substantially complete recovery ofmethane from a coal formation may yield between about 1 m³/ton and about30 m /ton. Methane recovered from thermal desorption during heating maybe used as fuel for an in situ treatment process. For example, methanemay be used for power generation to run electric heater wells. Inaddition, methane may be used as fuel for gas fired heater wells orcombustion heaters.

[2589] All or almost all methane that is entrained in a hydrocarboncontaining formation may be produced during an in situ conversionprocess. In an embodiment, freeze wells may be installed around aportion of a formation that includes adsorbed methane to define atreatment area. Heat sources, production wells, and/or dewatering wellsmay be installed in the treatment area prior to, simultaneously with, orafter installation of the freeze wells. The freeze wells may beactivated to form a frozen barrier that inhibits water inflow into thetreatment area. After formation of the frozen barrier, dewatering wellsand/or selected production wells may be used to remove formation waterfrom the treatment area. Some of the methane entrained within theformation may be released from the formation and recovered as the wateris removed. Heat sources may be activated to begin heating theformation. Heat from the heat sources may release methane entrained inthe formation. The methane may be produced from production wells in thetreatment area. Early production of adsorbed methane may significantlyimprove the economics of an in situ conversion process.

[2590] Freeze wells may be used to isolate deep coal beds (e.g., coal inthe Powder River Basin). Isolating the coal bed allows dewatering toremove coal bed methane gas. The coal beds often include aquifers withflow rates that would otherwise inhibit production of coal bed methane.The use of freeze wells may enable the dewatering of these coal beds andproduction of coal bed methane.

[2591] An in situ conversion process may alter hydrocarbon containingmaterial in a treatment area of a formation. Upon application of heat,hydrocarbon material such as coal may be converted and/or upgraded,thereby accelerating a process that would occur naturally overgeological time. Various properties of coal within a treatment area maybe altered including, but not limited to, a heating value, a vitrinitereflectance, a moisture content, a volatile matter percentage,permeability, porosity, concentrations of various components in the coalsuch as sulfur, and/or a carbon percentage. For example, coal within atreatment area may be considered a bituminous coal prior to treatment.Application of heat may alter the bituminous coal to form an anthracitecoal. An anthracite coal has a lower moisture content, a higher heatingvalue, and a higher carbon weight percent. In certain embodiments,anthracite coal may be used in metallurgical processing. Typically,anthracite coal is found in thin coal seams of a few meters thickness.The in situ conversion process may generate an anthracite seam from athick bituminous coal that is thicker than would be produced naturally.

[2592] In addition, the altered coal may have a high permeability andporosity. At least some of the coal heated using the in situ conversionprocess may, in certain embodiments, contain several fractures. In someinstances, at least a portion of the coal may be friable or in apowdered form. In some embodiments, coal treated with an in situconversion process may be easily mined using an underground automated orrobotic system to mine coal as a powder or as a slurry. For example,water jetting may be used to remove at least some coal in a slurry. Insome embodiments, an overburden may be removed by earth moving equipmentafter sufficient time has passed to allow the treated formation to coolto a temperature that allows for safe operation. In some embodiments,tunnels may be formed to coal that has been treated using an in situprocess. Traditional mining equipment may be used to reach and removethe coal.

[2593] Coal produced as a powder or in a slurry may be used in variousprocesses including, but not limited to, directly combusting coal at thesurface for use as an energy source and/or slurrying the coal andtransporting the coal for sale as an energy fuel. Such coal may be usedas an activated carbon filter to remove components from various waterand/or air streams within an in situ conversion process site and/or atexternal sites. The coal may alternately be used as an adsorbent (whichmay further upgrade the coal as a fuel) followed by combustion of thecoal for power, as an intermediate in dyes (e.g., anthraquinone), and/orin metallurgical processes. Treating coal with an in situ conversionprocess may alter the coal such that an economic value of the coalincreases and/or the costs associated with mining the coal decrease.

[2594] Water, in the form of saline or a solution with high levels ofdissolved solids, may be provided to a hot spent reservoir. Water to bedesalinated in a hot spent reservoir may originate from the ocean and/orfrom deep non-potable reservoirs. As water flows into the hot spentreservoir, the water may be evaporated and produced from the formationas steam. This water may be condensed into potable water having a lowtotal dissolved solids content. Condensation of the produced water mayoccur in treatment facilities or in subsurface conduits. Salts and otherdissolved solids may remain in the reservoir. The salts and dissolvedsolids may be stored in the reservoir. Alternatively, effluent fromtreatment facilities may be provided to a hot spent formation fordesalinization and/or disposal.

[2595] Utilizing a hot spent formation to desalinate fluids may recoversome heat from the formation. After a temperature within the formationfalls below a boiling point of a fluid, desalinization may cease.Alternatively, a section of a formation may be continually heated tomaintain conditions appropriate for desalinization. Desalinization maycontinue until a permeability and/or a porosity of a section issignificantly reduced from the precipitation of solids. In someembodiments, heat from treatment facilities may be used to run a surfacedesalinization plant, with produced salts and solids being injected intoa portion of the formation, or to preheat fluids being injected into theformation to minimize temperature change within the formation.

[2596] Water generated from a desalination process may be sold to alocal market for use as potable and/or agricultural water. Thedesalinated water may provide additional resources to geographical areasthat have severe water supply limitations.

[2597] Combustion of gaseous by-products from an in situ conversionprocess as well as fluids generated in treatment facilities may beutilized to generate heat and/or energy for use in the in situconversion process. For example, a low heating value stream (LHVstream), such as tail gas from the treating/recovery operations, may becatalytically combusted to generate heat and increase temperatures to arange needed for the in situ conversion process. A monolithic substrate(i.e., honeycomb such as Torvex (Du Pont) and/or Cordierite (Corning))with good flow geometry and/or minimal pressure drops may be used in thecombustor. In a conventional process, a gaseous by-product stream may beflared, since the heating value is considered too low to sustain stablethermal combustion. Utilizing energy in these streams may increase anoverall efficiency of the treatment system for formations.

[2598] A “kerogen and liquid hydrocarbon containing formation” is aformation that contains at least 5 volume % kerogen and at least 5volume % liquid hydrocarbons. The liquid hydrocarbons may include oilwith a grade that ranges between heavy hydrocarbons and lighthydrocarbons. The presence of liquid hydrocarbons in the formation maybe due to the, maturation of a portion of the kerogen. Alternatively,liquid hydrocarbons in the formation may have migrated into theformation from outside sources and become trapped. Liquid hydrocarbonsmay be present in the formation due to both maturation and migration.The Natih B formation in Oman is an example of a formation formed bymaturation and/or migration. The Natih B formation contains asubstantial amount of light hydrocarbons with kerogen.

[2599] The lithology of kerogen and liquid hydrocarbon containingformations may be shale, fine-grained carbonate such as chalk orlimestone, or some mixture of the two. The formations may containsiliceous materials such as diatomite and silicilyte. Kerogen and liquidhydrocarbon containing formations may include kerogenous shale,kerogenous chalk, siliceous kerogenous phosphatic shale, and/orkerogenous argillaceous limestone.

[2600] Kerogen and liquid hydrocarbon containing formations may have arelatively low permeability that ranges between about 0.1 millidarcy andabout 10 millidarcy. The relatively low permeability of kerogen andliquid hydrocarbon containing formations may be due to both the veryfine grain size in the formation matrix and to occlusion of the pores bythe kerogen. Relatively deep formations (i.e., at a depth greater thanabout 1500 m) may have overpressure (a pressure between hydrostatic andlithostatic) and natural fracturing. Relatively shallow formations, dueto later uplift and burial, may not preserve overpressures, but maystill be fractured.

[2601] Formation thicknesses may range from about 5 m to about 100 m.Most kerogen and liquid hydrocarbon containing formations were depositedduring the late Devonian, early Mississippian, Permian, Jurassic, orCretaceous periods.

[2602] An in situ process for treating a kerogen and liquid hydrocarboncontaining formation may include providing heat from one or more heatsources to at least a portion of the formation. The heat sources maytransfer heat to a selected section of the formation. The heat from theheat sources may mobilize at least a portion of the liquid hydrocarbonsin the selected section of the formation due to thermal expansion.Thermal expansion of the liquid hydrocarbons may create a pressuredifferential that drives the liquid hydrocarbons through the formation.The heat sources may transfer heat to the selected section such that atemperature of the selected section is sufficient to mobilize liquidhydrocarbons in the formation. A temperature sufficient to mobilizeliquid hydrocarbons in a kerogen and liquid hydrocarbon containingformation may be within a range from about 100° C. to about 270° C. Atleast a portion of the mobilized liquid hydrocarbons may be producedfrom the formation. Liquid hydrocarbons may be produced throughproduction wells placed in the formation.

[2603] Heat from the heat sources may pyrolyze a portion of the kerogenin the selected section of the formation. A temperature sufficient topyrolyze kerogen in a kerogen and liquid hydrocarbon containingformation may be within a range from about 270° C. to about 400° C.Production wells may produce a mixture from the formation that includespyrolyzation fluids and/or liquid hydrocarbons present in the formationprior to pyrolyzation. The mixture produced from the formation may alsoinclude some CO₂. In one embodiment, some of the CO₂ produced from theformation may separated from the produced fluid. The CO₂ may be used forenhanced oil recovery in a nearby oil field.

[2604] Pyrolyzation and removal of pyrolyzation products-may increasethe permeability of the selected section of the formation. The increasedpermeability may facilitate flow of liquid hydrocarbons originally inthe formation towards the production wells. The liquid hydrocarbonsoriginally present may be in a liquid phase and/or in a vapor phase dueto the heating of the formation. The liquid hydrocarbons originallypresent in the formation may be subject to pyrolyzation reactions withinthe formation.

[2605] In some embodiments, liquid hydrocarbons in the formation may below grade hydrocarbons such as heavy hydrocarbons. Heat from heatsources may mobilize and/or pyrolyze the low grade hydrocarbons. Atemperature sufficient to pyrolyze low grade hydrocarbons may be withina range from about 300° C. to about 375° C.

[2606] An average distance between heat sources in the formation may bebetween about 2 m and about 10 m. In some embodiments, an averagedistance between heat sources may be. greater than about 10 m. Inanother embodiment, the average distance may be about 60 m. Thepyrolyzation fluids may be produced through one or more production wellsplaced in the formation. In certain embodiments, an average spacingbetween production wells may be greater than about 80 m. Smallerproduction well spacings may be utilized. For example, a production wellspacing of about 20 m may be used in some embodiments.

[2607] In certain embodiments, heat from the heat sources may vaporizeaqueous fluids in the formation. Vaporization of the aqueous fluids mayincrease the permeability of the selected section. Thermal expansion ofthe aqueous fluids during vaporization may create a pressuredifferential that drives fluids through the formation towards lowpressure zones (e.g., regions at and surrounding production wells). Incertain embodiments, heat from the heat sources creates thermalfractures in the formation that increase the permeability of theformation and allow the light hydrocarbons to be produced.

[2608] In certain embodiments of treating a kerogen and liquidhydrocarbon containing formation, heat sources may be disposedhorizontally within the formation. In an embodiment, an average lengthof the heat sources in the formation may be between about 800 m andabout 1000 m. In other embodiments, the average length may be betweenabout 1000 m and about 1200 m. In addition, one or more production wellsmay also be disposed horizontally within the formation. Alternatively,one or more production wells may be disposed vertically or at anydesired angle within the formation.

[2609]FIG. 423 illustrates a schematic of a portion of a kerogen andliquid hydrocarbon containing formation. Heat source 508 may provideheat to a portion of formation 2960. Heat from heat source 508 may betransferred to selected section 2962. FIG. 424 illustrates an expandedview of selected section 2962. As shown in FIG. 424, selected section2962 may contain liquid hydrocarbons 2964 trapped within portions ofkerogen 2966. Selected section 2962 may also contain liquid hydrocarbons2968 that are not trapped within kerogen.

[2610] Heat from heat source 508 may mobilize a portion of liquidhydrocarbons 2968 due to thermal expansion. Liquid hydrocarbons 2968 maymigrate through the selected section due to increased pressure fromthermal expansion. Liquid hydrocarbons 2968 may be produced throughproduction well 512 shown in FIG. 423. Thermal fractures 2970 may freesome trapped kerogen and increase the permeability of the selectedsection to enhance the migration of the liquid hydrocarbons toproduction wells.

[2611] Heat from heat source 508 may pyrolyze a portion of kerogen 2966in selected section 2962. Pyrolyzation fluids from selected section 2962may be produced through production well 512. Liquid hydrocarbons 2964trapped within kerogen 2966 may be mobilized due to pyrolyzation of thekerogen and thermal expansion of the liquid hydrocarbons. Some liquidhydrocarbons 2964 may be produced through production well 512.

[2612] In certain embodiments, liquid hydrocarbons 2964 and 2968 may below grade hydrocarbons such as heavy hydrocarbons. Heat from heat source508 may mobilize and/or pyrolyze liquid hydrocarbons 2964 and 2968. Thepyrolyzation fluids may be produced through production well 512.

[2613]FIG. 425 is a schematic illustration of one embodiment ofproduction versus time or temperature from production well 512 shown inFIG. 423. The initial production up to and including the time period ortemperature range in the region of peak 2972 may correspond primarily toproduction of liquid hydrocarbons not trapped within kerogen. Thetemperature in the region of peak 2972 may be close to a mobilizationtemperature for liquid hydrocarbons. Liquid hydrocarbons 2968 shown inFIG. 424 may be an example of such liquid hydrocarbons. Fluids producedin the region near peak 2974 may include, for example, liquidhydrocarbons trapped within kerogen and pyrolyzation fluids fromkerogen. The temperature in the region of peak 2974 may be close to apyrolyzation temperature for kerogen.

[2614] Rock-Eval pyrolysis is a petroleum exploration tool developed toassess the generative potential and thermal maturity of prospectivesource rocks. In particular, Rock-Eval pyrolysis may be used todetermine the amount of hydrocarbons present in the form of kerogen andin the form of liquid hydrocarbons in a sample of a kerogen and liquidhydrocarbon containing formation. A ground sample may be pyrolyzed in ahelium atmosphere. FIG. 426 illustrates a schematic of a typicaltemperature profile of the Rock-Eval pyrolysis process. The sample isinitially heated and held at a temperature of about 300° C. for 5minutes, as shown by line 2976. The sample is further heated at a rateof 25° C./min to a final temperature of about 600° C. The finaltemperature is maintained for 1 minute. The products of pyrolysis areoxidized in a separate chamber at about 580° C. to determine the totalorganic carbon content. All components generated are split into twostreams passing through a flame ionization detector, which measureshydrocarbons, and a thermal conductivity detector, which measures CO₂.

[2615]FIG. 426 schematically illustrates the signal data obtained by theRock-Eval analysis. Line 2978 illustrates a typical signal output fromthe flame ionization detector. Peak 2980 represents the free thermallyliberated hydrocarbon present in the sample calculated as milligrams ofhydrocarbon per gram of the sample. Peak 2980 includes hydrocarbons thatare vaporized up to about 330° C. Hydrocarbons represented by peak 2980are primarily composed of liquid hydrocarbons that are present in thesource sample due to maturation or migration from outside the formation.Peak 2982 represents the hydrocarbons that result from cracking ofkerogen and any high molecular weight hydrocarbon such as heavyhydrocarbons that did not vaporize near peak 2980. Similarly, line 2984illustrates a typical signal output from the thermal conductivitydetector. Peak 2986 represents the carbon dioxide evolved during lowtemperature pyrolysis of 390° C. or less. Rock-Eval also provides theamount of residual carbon that has no potential to generate hydrocarbon.

[2616]FIGS. 427, 428, 429, and 430 illustrate embodiments of heater welland production well patterns used in simulations of an in situconversion process for a kerogen and liquid hydrocarbon containingformation similar to that found in the Natih B field in Oman. FIG. 427illustrates an aerial view of horizontal heater wells and horizontalproduction wells. In FIG. 427, triangles 2988 indicate heater wells andcircles 2990 indicate production wells. Lines 2992 represent thehorizontal extent of the heater wells and production wells in theformation. Horizontal length 2994 of the wells was 1000 m. Distance 2996between heater wells was 20 m. Distance 2998 between production wellswas 60 m. FIG. 428 illustrates a cross-sectional representation of thepattern with horizontal heater wells and-horizontal production wells.Depth 3000 of the pattern was 66 m. The ratio of heater wells toproduction wells for the pattern was 4:1.

[2617]FIG. 429 illustrates an aerial view of horizontal heater wells andvertical production wells. In FIG. 429 and FIG. 430, triangles indicateheater wells and circles indicate production wells. Distance 3002between heater wells was 20 m. Length 3004 of the heater wells was 1000m. Distance 3006 between the vertical production wells was 80 m. A totalof 12 production wells per pattern was used. FIG. 430 illustrates across-sectional representation of the pattern with horizontal heaterwells and vertical production wells. Depth 3008 of the pattern was 66 m.The ratio of heater wells to production wells was 4:3.

[2618] A summary of the parameters and results of the reservoirsimulation are given in TABLE 30. Inputs into the simulator included theoil and kerogen in place for the formation and geologic data for theformation. The oil and kerogen in place represent the total amount ofcondensables that would be produced from the formation given 100%recovery. The recovery was estimated to be 70%. The richness andoil:kerogen ratio were determined from Rock-Eval analysis of a sample ofthe formation. The richness is the amount of condensables that may beproduced per ton of the formation. The oil:kerogen ratio represents theratio of liquid hydrocarbons to kerogen in the formation prior totreatment. The condensable production was determined by the simulator.The total production of non-condensables was determined from the kerogenand oil in place, the recovery, and the non-condensable:condensablevolumetric production ratio. TABLE 30 SUMMARY OF THE PARAMETERS ANDRESULTS OF SIMULATION. Pattern Size 20 m × 20 m Depth 66 mHeater-Production Well Ratio: 4/1 Horizontal heater wells and Horizontalproduction wells Heater-Production Well Ratio: 4/3 Horizontal heaterwells and Vertical production wells Patterns/Year 82 Total Patterns 1732Drilling Time 21 years Production Life 28 years Pattern Life 9 yearsRecovery 70% Richness 0.114 m³/ton Pretreatment Oil:Kerogen Ratio 0.53Oil and Kerogen in Place 171.1 MM m³ Condensable Production 15,900m³/day Non-condensable:Condensable 356 Volumetric Production RatioNon-condensable Total Production 42,657 m³

[2619]FIG. 431 illustrates the production of condensables andnon-condensables per pattern as a function of time in years from an insitu conversion process as calculated by the simulator. Line 3010represents the production of condensables in thousands of cubic metersas a function of time in years. Line 3012 represents the production ofnon-condensables in millions of cubic meters as a function of time inyears. The production of both condensables and non-condensablesdecreases from about 7 years to about 9 years, which is the projectedend of the pattern life.

[2620]FIG. 432 illustrates the total production of condensables andnon-condensables as a function of time in years from an in situconversion process as calculated by the simulator. Line 3014 is thetotal production of condensables as a function of time in years. Line3016 is the total production of non-condensables as a function of timein years. FIG. 432 shows that the productions of condensables andnon-condensables are at steady state between about 12 years and about 23years.

[2621]FIG. 433 shows the annual heat injection rate per pattern versustime calculated by the simulator. The heat injection rate calculationassumes a value of the density of the formation multiplied by the heatcapacity (ρC_(p)) of 2.5×10⁶ J/m³ K. The heat injection rate calculationwas based on heat-transfer calculations performed for oil shale in NorthAmerica. This assumption gives a conservative estimate of the heatinjection rate that may be achieved in the Natih B kerogen and liquidhydrocarbon containing formation.

[2622] U.S. Pat. No. 4,640,352 to Van Meurs et al., which isincorporated by reference as if fully set forth herein, describes amethod for recovering hydrocarbons (e.g., heavy hydrocarbons) from a lowpermeability subterranean reservoir of the type comprised primarily ofdiatomite. At least two wells may be completed into a treatment intervalhaving a thickness of at least about 30 m within an oil andwater-containing zone. The zone may be both undesirably impermeable andnon-productive in response to injections of oil-displacing fluids. Thewells may be arranged to provide at least one each of heat-injecting andfluid-producing wells having boreholes. The wells may, substantiallythroughout the treatment interval, be substantially parallel andseparated by substantially equal distances of at least about 6 m. Ineach heat-injecting well, substantially throughout the treatmentinterval, the face of the reservoir formation may be sealed with a solidmaterial or cement which is relatively heat conductive and substantiallyfluid impermeable. Sealing of each heat-injecting well may inhibit fluidfrom flowing between the interior of the borehole and the reservoir. Ineach fluid-producing well, substantially throughout the treatmentinterval, fluid communication may be established between the wellborehole and the reservoir formation and the well is arranged forproducing fluid from that formation.

[2623] Heavy hydrocarbons may be contained in diatomite formations. Theterm “diatomite formation” is defined as a formation of a siliceoussedimentary rock composed of the siliceous skeletal remains ofsingle-celled aquatic plants called “diatoms.”

[2624] Heavy hydrocarbons containing diatomite formations may have arelatively high porosity, high internal surface area, high absorptivecapacity, relatively low permeability, and relatively high oilsaturation. “Relatively high porosity” is, with respect to diatomite orportions thereof, an average porosity of greater than about 50%. The lowpermeability of diatomite formations may be due to the scarcity of flowchannels or fractures through which oil may flow and, ultimately, berecovered. Such deposits, in addition to the oil saturated diatomaceousparticles, may also contain some fine clay, silt, and water.

[2625] An “oil containing formation” is a rock formation that includesmicroscopic pores in coarser sediments of rock. The rock may be composedof shales, limestone, and carbonates. Oil may be present in intersticesbetween rocks and within the pores. An oil containing formationgenerally has a relatively high porosity and relatively high oilsaturation. The average porosity may be greater than about 15%. Theaverage oil saturation may be greater than about 40%. Oil containingformations may have sections greater than about 10 m in thickness.

[2626] In an embodiment, heat sources may be initiated in stages tocontrol the volumetric production rate. Staging may allow substantiallyconstant production throughout production from the formation (e.g.,ignoring initial heating time of the first stage).

[2627] In certain embodiments, a portion of the formation fluids inrelatively deep sections of a formation may reach a supercritical state.Condensable and non-condensable formation fluids in a supercriticalstate may become miscible, which may allow single-phase flow through thedeep sections of the formation.

[2628] Fractures may be created by expansion of the heated portion ofthe formation matrix. In addition, fractures may also be created byincreased pressure from expanding formation fluids and productsgenerated from pyrolysis. In some embodiments, hydrocarbons such askerogen, pyrobitumen, and/or bitumen may block pores in a portion of theformation. Such hydrocarbons may dissolve or pyrolyze during heating,resulting in an increase in the permeability of the portion of theformation.

[2629] In one embodiment, vaporization of the aqueous fluids in pores ofthe formation may result in separation of hydrocarbons from water. Thevaporizing water may cause some local fracturing of the rock matrix.Hydrocarbons may migrate by film drainage, which may further increasethe effective permeability of the formation. The relatively lowviscosity of the hydrocarbons may increase the possibility of migrationof hydrocarbons by film drainage. The relatively low viscosity may bedue to the relatively high temperature in the formation.

[2630] In certain embodiments, heat from the heat sources may shrinkclays present in a portion of the formation. Shrinkage of the clay mayincrease permeability of the portion.

[2631] In an embodiment, a method of treating an oil containingformation in situ may include injecting a recovery fluid into aformation. The recovery fluid may be water. Heat from one or more heatsources may provide heat to the formation. At least one of the heatsources may be an electric heater. In one embodiment, at least one ofthe heat sources may be located in a heater well. A heater well mayinclude a conduit through which flows a hot fluid that transfers heat tothe formation. At least some of the recovery fluid in a selected sectionof the formation may be vaporized by heat from the heat sources. Forexample, water may be vaporized into steam. Heat from the heat sourcesand the vaporized recovery fluid may pyrolyze at least some hydrocarbonswithin the selected section. A temperature for pyrolysis may be fromabout 270° C. to about 400° C.

[2632] A gas mixture that includes pyrolyzation fluids and steam may beproduced from the formation. In one embodiment, fluids may be producedthrough a production well. The pressure at or near the heat sources mayincrease due to thermal expansion of the formation and vaporization ofthe recovery fluid. The pressure differential between the heat sourcesand production wells may force steam and/or pyrolyzation fluids towardthe production wells. In one embodiment, the gas mixture may includehydrocarbons having an average API gravity greater than about 25°.

[2633]FIG. 434 illustrates a schematic of an embodiment of in situtreatment of an oil containing formation. FIG. 434 includes formation3018 with heat source well 3020 and production well 512. The wells maybe members of a larger pattern of wells placed throughout a portion ofthe formation. Recovery fluid 3022 may be injected into the formationthrough heat source well 3020. Water may be used as a heat recoveryfluid. Heat from heat source well 3020 may vaporize some of the water inthe formation to produce steam. Heat from the heat sources and/or thesteam may pyrolyze hydrocarbons in the formation.

[2634] In an embodiment, a pressure differential may be created inregion 3024 between heat source well 3020 and production well 512 due tothermal expansion of the formation and vaporization of the steam. Steamand pyrolyzation fluids may be forced by the pressure gradient from heatsource well 3020 towards production well 512. Steam and pyrolyzationfluids stream 3026 may be produced from production well 512.

[2635] Stream 3026 may be fed to surface separation unit 3028.Separation unit 3028 may separate stream 3026 into stream 3030 andhydrocarbons 594. Stream 3030 may be composed primarily of steam orwater. Steam may be used in power generation units 1798 or heat exchangemechanisms 2858 or injected back into the formation.

Further Improvements

[2636] In certain embodiments, acoustic waves and their reflections maybe used to determine the approximate location of a wellbore within ahydrocarbon layer (e.g., a coal layer). In some embodiments, loggingwhile drilling (LWD), seismic while drilling (SWD), and/or measurementwhile drilling (MWD) techniques may be used to determine a location of awellbore while the wellbore is being drilled. Examples of thesetechniques are disclosed in U.S. Pat. Nos. 5,899,958 to Dowell et al.;6,078,868 to Dubinsky; 6,084,826 to Leggett, III; 6,088,294 to Leggett,III et al.; and 6,427,124 to Dubinsky et al., each of which isincorporated by reference as if fully set forth herein.

[2637] In an embodiment, an acoustic source may be placed in a wellborebeing formed in a hydrocarbon layer (e.g., the acoustic source may beplaced at, near, or behind the drill bit being used to form thewellbore). The location of the acoustic source may be determinedrelative to one or more geological discontinuities (e.g., boundaries) ofthe formation (e.g., relative to the overburden and/or the underburdenof the hydrocarbon layer). The approximate location of the acousticsource (i.e., the drilling string being used to form the wellbore) maybe assessed while the wellbore is being formed in the formation.Monitoring of the location of the acoustic source, or drill bit, may beused to guide the forming of the wellbore so that the wellbore is formedat a desired distance from, for example, the overburden and/or theunderburden of the formation. For example, if the location of theacoustic source drifts from a desired distance from the overburden orthe underburden, then the forming of the wellbore may be adjusted toplace the acoustic source at a selected distance from a geologicaldiscontinuity. In some embodiments, a wellbore may be formed atapproximately a midpoint in the hydrocarbon layer between the overburdenand the underburden of the formation (i.e., the wellbore may be placedalong a midline between the overburden and the underburden of theformation).

[2638]FIG. 435 depicts an embodiment for using acoustic reflections todetermine a location of a wellbore in a formation. Drill bit 3031 may beused to form opening 544 in hydrocarbon layer 522. Drill bit 3031 may becoupled to drill string 3032. Acoustic source 3034 may be placed at ornear drill bit 3031. Acoustic source 3034 may be any source capable ofproducing an acoustic wave in hydrocarbon layer 522 (e.g., acousticsource 3034 may be a monopole source or a dipole source that produces anacoustic wave with a frequency between about 2 kHz and about 10 kHz).Acoustic waves 3036 produced by acoustic source 3034 may be measured byone or more acoustic sensors 3038. Acoustic sensors 3038 may be placedin drill string 3032. In an embodiment, 3 to 10 (e.g., 8) acousticsensors 3038 are placed in drill string 3032. Acoustic sensors 3038 maybe spaced between about 5 cm and about 30 cm apart (e.g., about 15.2 cmapart). The spacing between acoustic sensors 3038 and acoustic source3034 is typically between about 5 meters and about 30 meters (e.g.,between about 9 meters and about 15 meters).

[2639] In an embodiment, acoustic sensors 3038 may include one or morehydrophones (e.g., piezoelectric hydrophones) or other suitable acousticsensing device. Hydrophones may be oriented at 90° intervalssymmetrically around the axis of drill string 3032. In certainembodiments, the hydrophones may be oriented such that respectivehydrophones in each acoustic sensor 3038 are aligned in similardirections. Drill string 3032 may also include a magnetometer, anaccelerometer, an inclinometer, and/or a natural gamma ray detector.Data at each acoustic sensor 3038 may be recorded separately using, forexample, computational software for acoustic reflection recording (e.g.,BARS acquisition hardware/software available from SchlumbergerTechnology Co. (Houston, Tex.)). Data may be recorded at acousticsensors 3038 at an interval between about every 1 μsec and about every50 μsec (e.g., about every 15 μsec).

[2640] Acoustic waves 3036 produced by acoustic source 3034 may reflectoff of overburden 524, underburden 914, and/or other unconformities orgeological discontinuities (e.g., fractures). The reflections ofacoustic waves 3036 may be measured by acoustic sensors 3038. Theintensities of the reflections of acoustic waves 3036 may be used toassess or determine an approximate location of acoustic source 3034relative to overburden 524 and/or underburden 914. For example, theintensity of a signal from a boundary that is closer to the acousticsource may be somewhat greater than the intensity of a signal from aboundary further away from the acoustic source. In addition, the signalfrom a boundary that is closer to the acoustic source may be detected atan acoustic sensor at an earlier time than the signal from a boundaryfurther away from the acoustic source.

[2641] Data acquired from acoustic sensors 3038 may be processed todetermine the approximate location of acoustic source 3034 inhydrocarbon layer 522. In certain embodiments, data from acousticsensors 3038 may be processed using a computational system or othersuitable system for analyzing the data. The data from acoustic sensors3038 may be processed by one or more methods to produce suitableresults.

[2642] In one embodiment, acoustic waves 3036 that are reflected fromgeological discontinuities (e.g., boundaries of the formation) aredetected at two or more acoustic sensors 3038. The reflected acousticwaves may arrive at the acoustic sensors later than refracted acousticwaves and/or with a different moveout across the array of acousticsensors. The local wave velocity in the formation may be assessed, orknown, from analysis of the arrival times of the refracted acousticwaves. Using the local wave velocity, the distance of a selectedreflecting interface (i.e., geological discontinuity) may be assessed(e.g., computed) by assessing the appropriate arrival time for thereflection from the selected reflecting interface when the acousticsource and the acoustic sensor are not separated (i.e., zero offset),multiplying the assessed appropriate arrival time by the local wavevelocity, and dividing the product by two. The zero offset arrival timemay be assessed by applying normal moveout corrections for the assessedlocal wave velocity to the recorded waveforms of the acoustic waves ateach acoustic sensor and stacking the corrected waveforms in a commonreflection point gather. This process is generally known and commonlyused in surface exploration reflection seismology.

[2643] The direction from which a particular acoustic wave originates(e.g., above or below opening 544) may be assessed with a knowledge ofthe angle of the opening, which may be provided by a wellbore survey,and an estimate of the dip of hydrocarbon layer 522, which may be madeby a surface seismic section. If the opening dips with respect to theformation itself, an upcoming wave (i.e., a wave coming from below theopening) may be separated from a downgoing wave (i.e., a wave comingfrom above the opening) by the sign of the apparent velocities of thewaves in a common acoustic sensor panel composed over a substantiallength of the opening. For a formation with a uniform thickness and anopening with a distance from the top and bottom of the formation thatdoes not substantially vary along a length of the opening beingmonitored, polarized detectors may be used to assess the direction fromwhich an acoustic wave arrives at an acoustic sensor.

[2644] In certain embodiments, filtering of the data may enhance thequality of the data (e.g., removing external noises such as noise fromdrill bit 3031). Frequency and/or apparent velocity filtering may beused to suppress coherent noises in the data collected from acousticsensors. Coherent noises may include unwanted and intense noise fromevents such as earlier refracted arrivals, direct fluid waves, wavesthat may propagate in the drill sting or logging tool, and/or Stoneleywaves. Data filtering may also include bandpass filtering, f-k dipfiltering, wavelet-processing Wiener filtering, and/or wave separationfiltering. Filtering may be used to reduce the effects of wellbore wavesignal modes (e.g., compressional headwaves) in common shot, commonreceiver, and/or common offset modes. In some embodiments, filtering ofthe data may include accounting for the velocity of acoustic waves inthe formation. The velocity of acoustic waves in the formation may becalculated or assessed by, for example, acoustic well logging and/oracoustic measurements on a core sample from the formation. The data mayalso be processed by binning, normal moveout, and/or stacking (e.g.,prestack migration). In some embodiments, the data may be processed bybinning, normal moveout, and/or stacking followed by a second stackingtechnique (e.g., poststack migration). Prestack migration and poststackmigration may be based on the generalized Radon transform. In certainembodiments, results from processing the data may be displayed and/oranalyzed following any method of processing the data so that the datamay be monitored (e.g., for quality control purposes).

[2645] In an embodiment, processed data may be analyzed to providefeedback control to drill bit 3031. Direction of drill bit 3031 may bemodified or adjusted if the location of acoustic source 3034 varies froma desired spacing relative to geological discontinuities (e.g.,overburden 524 and/or underburden 914) so that opening 544 may be formedat a desired location (e.g., at a desired spacing between the overburdenand the underburden). For example, drill string 3032 may include aninclinometer that is used to direct the forming (i.e., drilling) ofopening 544. The direction of the inclinometer may be adjusted tocompensate for variance of the location of acoustic source 3034 from thedesired location between overburden 524 and/or underburden 914. Anadvantage of using data from acoustic sensors 3038 while drilling anopening in the formation may be the real-time monitoring of the locationof drill bit 3031 and/or adjusting the direction of drilling in realtime. In some embodiments, opening 544 formed using acoustic data tocontrol the location of the opening may be used as a guide opening forforming one or more additional openings in a formation (e.g., magnetictracking of opening 544 may be used to form one or more additionalopenings).

[2646] In an embodiment, a hydrocarbon containing formation may bepre-surveyed before drilling to determine the lithology of the formationand/or the optimum geometry of acoustic sources and sensors.Pre-surveying the formation may include simulating refraction signalsfor compressional and/or shear waves, various reflection mode signals ina wellbore, mud wave signals, Stoneley wave signals (i.e., seamvibration), and other reflective or refractive wave signals in theformation. In one embodiment, reflected signals may be determined bythree-dimensional (3-D) ray tracing (an example of 3-D ray tracing isavailable from Schlumberger Technology Co. (Houston, Tex.)). Simulatingthese signals may provide an estimate of the optimum parameters foroperating sensors and analyzing sensor data. In addition, pre-surveyingmay include determining if acoustic waves can be measured and analyzedefficiently within a formation.

[2647]FIG. 436 depicts an embodiment for using acoustic reflections andmagnetic tracking to determine a location of a wellbore in a formation.Measurements of acoustic waves 3036 may be used to assess an approximatelocation of opening 544 relative to geological discontinuities (e.g.,overburden 524 and/or underburden 914). Magnetic tracking may be used toassess an approximate location of opening 544 relative to one or moreadditional wellbores in the formation. The combination of measurementsof acoustic waves and magnetic tracking in a wellbore (e.g., opening544) may increase the accuracy of placing the wellbore (e.g., theaccuracy of drilling of the wellbore) in hydrocarbon layer 522 or anyother subsurface formation or subsurface layer. Drill bit 3031 may beused to form opening 544 in hydrocarbon layer 522. Drill bit 3031 may becoupled to a turbine (e.g., a mud turbine) to turn the drill bit. Theturbine may be located at or behind drill bit 3031 in drill string 3032.Non-magnetic section 3033 may be located behind drill bit 3031 in drillstring 3032. Non-magnetic section 3033 may inhibit magnetic fieldsgenerated by drill bit 3031 from being conducted along a length of drillstring 3032. In an embodiment, non-magnetic section 3033 includesMonel®. In certain embodiments, acoustic source 3034 may be placed innon-magnetic section 3033. In other embodiments, acoustic source 3034may be placed in sections of drill string 3032 behind non-magneticsection 3033 (e.g., in probe section 3035).

[2648] In an embodiment, drill string 3032 may include probe section3035. Probe section 3035 may include inclinometer 3039 (e.g., a 3-axisinclinometer) and/or magnetometer 3037 (e.g., a 3-axis fluxgatemagnetometer.). In an embodiment, magnetometer 3037 may be used todetermine a location of opening 544 relative to one or more additionalopenings in hydrocarbon layer 522. Inclinometer 3039 may be used toassess the orientation and/or control the drilling angle of drill bit3031.

[2649] Acoustic sensors 3038 may be located in drill string 3032 behindprobe section 3035. In some embodiments, acoustic sensors 3038 may belocated in probe section 3035. In some embodiments, acoustic sensors3038, probe section 3035 (including inclinometer 3039 and/ormagnetometer 3037), and acoustic source 3034 may be located at otherpositions along a length of drill string 3032.

[2650]FIG. 437 depicts signal intensity (I) versus time (t) for raw dataobtained from an acoustic sensor in a formation. The raw data was takenfor a single shot of an acoustic source in a horizontal wellbore in acoal seam. The coal seam had a thickness of about 30 feet (9.1 m). Theacoustic source was separated from eight evenly spaced acoustic sensorsby distances from 15 feet (4.6 m) to 18.5 feet (5.6 m). Four separateplanar piezoelectric hydrophones were included in each acoustic sensor.The four hydrophones were oriented at 90° intervals symmetrically aroundthe axis of the drilling string. The data shown in FIG. 437 is for asingle hydrophone. The drilling string included a magnetometer andaccelerometers, for determining the orientation of the drilling stringand drill bit, and a natural gamma ray detector. The four hydrophones ateach acoustic sensor were recorded separately using BARS acquisitionhardware/software from Schlumberger Technology Co. (Houston, Tex.). Atotal of 32 512-sample traces were recorded at a 15 μsec sampling rateafter firing the source.

[2651] The arrival times of the P-wave refraction (3041) and the P-wavereflection (3043) are indicated in FIG. 437. The P-wave reflection had alater arrival time than the P-wave refraction. The P-wave reflection wasassessed as a reflection event because the P-wave reflection arrivedwith a higher velocity than the refracted P-wave, which has the highestvelocity speed possible for a direct arrival. Modeling of the P-wavevelocity in the coal derived from the P-wave refraction arrival and thegeometry of the acoustic devices indicated that the distance from thehorizontal wellbore to the reflector producing the P-wave reflection wasabout 16 feet (4.9 m). This result indicated that the wellbore waswithin ±1 foot (0.3 m) of the center of the coal seam. Magnetic sensingof magnetic fields produced by a wireline placed in a second wellboreindicated that distance between the wellbores was approximately thedesired distance of 20 feet (6.1 m).

[2652] Rotating magnet ranging may be used to monitor the distancebetween wellbores. Vector Magnetics LLC (Ithaca, N.Y.) uses one exampleof a rotating magnet ranging system. In rotating magnet ranging, amagnet rotates with the drill bit in one wellbore to generate a magneticfield. A magnetometer in another wellbore is used to sense the magneticfield produced by the rotating magnet. Data from the magnetometer can beused to measure the coordinates (x, y, and z) of the drill bit inrelation to the magnetometer.

[2653] In some embodiments, magnetostatic steering may be used to formopenings adjacent to a first opening. U.S. Pat. No. 5,541,517 issued toHartmann et al. describes a method for drilling a wellbore relative to asecond wellbore that has magnetized casing portions.

[2654] When drilling a wellbore (opening), a magnet or magnets may beinserted into a first opening to provide a magnetic field used to guidea drilling mechanism that forms an adjacent opening or adjacentopenings. The magnetic field may be detected by a 3-axis fluxgatemagnetometer in the opening being drilled. A control system may useinformation detected by the magnetometer to determine and implementoperation parameters needed to form an opening that is a selecteddistance away (e.g., parallel) from the first opening (within desiredtolerances).

[2655] Various types of wellbores may be formed using magnetic tracking.For example, wellbores formed by magnetic tracking may be used for insitu conversion processes (i.e., heat source wellbores, productionwellbores, injection wellbores, etc.), for steam assisted gravitydrainage processes, the formation of perimeter barriers or frozenbarriers (i.e., barrier wells or freeze wells), and/or for soilremediation processes. Magnetic tracking may be used to form wellboresfor processes that require relatively small tolerances or variations indistances between adjacent wellbores. For example, freeze wells may needto be positioned parallel to each other with relatively little or novariance in parallel alignment to allow for formation of a continuousfrozen barrier around a treatment area. In addition, vertical and/orhorizontally positioned heater wells and/or production wells may need tobe positioned parallel to each other with relatively little or novariance in parallel alignment to allow for substantially uniformheating and/or production from a treatment area in a formation. In anembodiment, a magnetic string may be placed in a vertical well (e.g., avertical observation well). The magnetic string in the vertical well maybe used to guide the drilling of a horizontal well such that thehorizontal well passes the vertical well at a selected distance relativeto the vertical well and/or at a selected depth in the formation.

[2656] In an embodiment, analytical equations may be used to determinethe spacing between adjacent wellbores using measurements of magneticfield strengths. The magnetic field from a first wellbore may bemeasured by a magnetometer in a second wellbore. Analysis of themagnetic field strengths using derivations of analytical equations maydetermine the coordinates of the second wellbore relative to the firstwellbore.

[2657] North and south poles may be placed along the z axis with a northpole placed at the origin and north and south poles placed alternatelyat constant separation L/2 out to z=±∞, where z is the location alongthe z-axis and L is the distance between consecutive north andconsecutive south poles. Let all the poles be of equal strength P. Themagnetic potential at position (r, z) is given by: $\begin{matrix}{{\Phi \left( {r,z} \right)} = {\frac{P}{4\pi}{\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}{\left\{ {r^{2} + \left( {z - {{nL}/2}} \right)^{2}} \right\}^{{- 1}/2}.}}}}} & (82)\end{matrix}$

[2658] The radial and axial components of the magnetic field are givenby: $\begin{matrix}{{B_{r} = {- \frac{\partial\Phi}{\partial r}}}{and}} & (83) \\{B_{z} = {- {\frac{\partial\Phi}{\partial z}.}}} & (84)\end{matrix}$

[2659] EQN. 82 can be written in the form: $\begin{matrix}{{{\Phi \left( {r,z} \right)} = {\frac{P}{2\pi \quad L}{f\left( {{2{r/L}},{2{z/L}}} \right)}}}{with}} & (85) \\{{f\left( {\alpha,\beta} \right)} = {\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}{\left\{ {\alpha^{2} + \left( {\beta - n} \right)^{2}} \right\}^{{- 1}/2}.}}}} & (86)\end{matrix}$

[2660] For values of α and β in the ranges αε[0,∞], βε[−∞,∞], replacingn by −n in EQN. 86 yields the result:

ƒ(α,−β)=ƒ(α,β).  (87)

[2661] Therefore only positive β may be used to evaluate ƒ accurately.Furthermore:

ƒ(α, m+β)=(−1)^(m)β(α,β), m=0,±1,  (88)

and ƒ(α,1−β)=−ƒ(α,β).  (89)

[2662] EQNS. 88 and 89 suggest the limit of βε[0,1/2]. The summation onthe right-hand side of EQN. 86 converges to a finite answer for all αand β except when α=0 and β is an integer. However, unless α is small,it converges too slowly for practical use in evaluating ƒ(α,β). Thus, αis transformed to obtain a much more rapidly convergent expression. Thetransformation: $\begin{matrix}{{\left\{ {\alpha^{2} + \left( {\beta - n} \right)^{2}} \right\}^{{- 1}/2} = {\frac{2}{\pi}{\int_{0}^{\infty}{\left. {k\left( {k^{2} + \alpha^{2} + \left( {\beta - n} \right)^{2}} \right.} \right\}^{- 1}}}}},} & (90)\end{matrix}$

[2663] can be used.

[2664] Substituting EQN. 90 into EQN. 89 and interchanging the summationand integration results in: $\begin{matrix}{{{f\left( {\alpha,\beta} \right)}{\int_{0}^{\infty}{{{kg}\left( {k,\alpha,\beta} \right)}}}},{with}} & (91) \\{{g\left( {k,\alpha,\beta} \right)} = {\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}{\left\{ {k^{2} + \alpha^{2} + \left( {\beta - n} \right)^{2}} \right\}^{- 1}.}}}} & (92)\end{matrix}$

[2665] Further, it can be shown that g can be expressed in terms ofhyperbolic and trigonometric functions. A simple special case is:$\begin{matrix}{{g\left( {k,\alpha,0} \right)} = {{\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}\left\{ {k^{2} + \alpha^{2} + n^{2}} \right\}^{- 1}}} = {\frac{\pi}{\sqrt{k^{2} + \alpha^{2}}{\sinh \left( {\pi \sqrt{k^{2} + \alpha^{2}}} \right)}}.}}} & (93)\end{matrix}$

[2666] Substituting EQN. 93 into EQN. 91, making the change of variablek=αu, expanding out the sinh function, and using the fact that:$\begin{matrix}{{K_{0}(z)} = {{\int_{0}^{\infty}{{t}\quad {\exp \left( {{- z}\quad \cosh \quad t} \right)}}} = {\int_{0}^{\infty}{{{u\left( {1 + u^{2}} \right)}^{{- 1}/2}}\exp \left\{ {{- {z\left( {1 + u^{2}} \right)}^{1/2}},} \right.}}}} & (94)\end{matrix}$

[2667] results in: $\begin{matrix}{{f\left( {\alpha,0} \right)} = {4{\sum\limits_{m = 0}^{\infty}{K_{0}{\left\{ {\left( {{2m} + 1} \right){\pi\alpha}} \right\}.}}}}} & (95)\end{matrix}$

[2668] To treat the general case, let:

γ² =k ²+α²  (96)

[2669] and use the identity: $\begin{matrix}{{\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}\left\{ {\gamma^{2} + \left( {\beta - n} \right)^{2}} \right\}^{- 1}}} = {\frac{1}{2\gamma}{\sum\limits_{n = {- \infty}}^{\infty}{\left( {- 1} \right)^{n}{\left\{ {\frac{\gamma + {i\quad \beta}}{n^{2} + \left( {\gamma + {i\quad \beta}} \right)^{2}} + \frac{\gamma - {i\quad \beta}}{n^{2} + \left( {\gamma - {i\quad \beta}} \right)^{2}}} \right\}.}}}}} & (97)\end{matrix}$

[2670] EQN. 93 therefore may be generalized to: $\begin{matrix}{{{g\left( {k,\alpha,\beta} \right)} = {\frac{\pi}{2\quad \gamma}\left\{ {\frac{1}{\sinh \left\{ {\pi \left( {\gamma + {i\quad \beta}} \right)} \right.} + \frac{1}{\sinh \left\{ {\pi \left( {\gamma - {i\quad \beta}} \right)} \right.}} \right\}}},} & (98)\end{matrix}$

[2671] and expanding out the hyperbolic sines as before results in:$\begin{matrix}{{f\left( {\alpha,\beta} \right)} = {4{\sum\limits_{m = 0}^{\infty}{K_{0}\left\{ {\left( {{2\quad m} + 1} \right)\pi \quad \alpha} \right\} \cos {\left\{ {\left( {{2\quad m} + 1} \right)\pi \quad \beta} \right\}.}}}}} & (99)\end{matrix}$

[2672] Substituting EQN. 99 back into EQN. 85 then yields:$\begin{matrix}{~{{\Phi \left( {r,z} \right)} = {\frac{2\quad P}{\pi \quad L}{\sum\limits_{m = 0}^{\infty}{K_{0}\left\{ {\left( {{2\quad m} + 1} \right)2\pi \quad {r/L}} \right\} \cos {\left\{ {\left( {{2\quad m} + 1} \right)2\quad \pi \quad {z/L}} \right\}.}}}}}} & (100)\end{matrix}$

[2673] The differentiations in EQNS. 83 and 84 may then be performed togive the following expressions for the field components: $\begin{matrix}{B_{r} = {\frac{4\quad P}{L^{2}}{\sum\limits_{m = 0}^{\infty}{\left( {{2m} + 1} \right)K_{1}\left\{ {\left( {{2\quad m} + 1} \right)2\quad \pi \quad {r/L}} \right\} \cos \left\{ {\left( {{2\quad m} + 1} \right)2\quad \pi \quad {z/L}} \right\}}}}} & (101)\end{matrix}$

$\begin{matrix}{{and}{B_{z} = {\frac{4\quad P}{L^{2}}{\sum\limits_{m = 0}^{\infty}{\left( {{2\quad m} + 1} \right)K_{0}\left\{ {\left( {{2\quad m} + 1} \right)\quad 2\quad \pi \quad {r/L}} \right\} \sin {\left\{ {\left( {{2\quad m} + 1} \right)2\quad \pi \quad {z/L}} \right\}.}}}}}} & (102)\end{matrix}$

[2674] For large arguments, the analytical functions have the followingasymptotic form: $\begin{matrix}{{K_{0}(z)},{{K_{1}(z)} \sim {\sqrt{\frac{\pi}{2\quad z}}{{\exp \left( {- z} \right)}.}}}} & (103)\end{matrix}$

[2675] For sufficiently large r, then, EQNS. 101 and 102 may beapproximated by: $\begin{matrix}{B_{r} \sim {\frac{2\quad P}{L^{2}}\sqrt{\frac{L}{r}}{\exp \left( {{- 2}\quad \pi \quad {r/L}} \right)}{{\cos \left( {2\quad \pi \quad {z/L}} \right)}.\quad {and}}}} & (104) \\{B_{z} \sim {\frac{2\quad P}{L^{2}}\sqrt{\frac{L}{r}}{\exp \left( {{- 2}\quad \pi \quad {r/L}} \right)}{{\sin \left( {2\quad \pi \quad {z/L}} \right)}.}}} & (105)\end{matrix}$

[2676] Thus, the magnetic field strengths B_(r) and B_(z) may be used toestimate the position of the second wellbore relative to the firstwellbore by solving EQNS. 104 and 105 for r and z. FIG. 452 depictsmagnetic field strength versus radial distance calculated using theabove analytical equations. As shown in FIG. 452, the magnetic fieldstrength drops off exponentially as the radial distance from themagnetic field source increases. The exponential functionality ofmagnetic field strengths, B_(r) and B_(z), with respect to r enablesmore accurate determinations of radial distances. Such improved accuracymay be a significant advantage when attempting to drill wellbores withsubstantially uniform spacings.

[2677] The magnets may be moved (e.g., by moving a magnetic string) withthe magnetometer sensors stationary and multiple measurements may betaken to remove fixed magnetic fields (e.g., earth's magnetic field,other wells, other equipment, etc.) from affecting the measurement ofthe relative position of the wellbores. In an embodiment, two or moremeasurements may be used to eliminate the effects of fixed magneticfields such as the Earth's magnetic field and the fields from othercasings. A first measurement may be taken at a first location. A secondmeasurement may be taken at a second location L/4 from the firstlocation. A third measurement may be taken at a third location L/2 fromthe first location. Because of sinusoidal variations along the z-axis,measurements at L/2 apart may be about 180° out of phase. At least twoof the measurements (e.g., the first and third measurements) may bevectorially subtracted and divided by two to remove/reduce fixedmagnetic field effects. Specifically, when this subtraction is done, thecomponents attributable to fixed magnetic field effects, being constant,are removed. At the same time, the 180° out of phase componentsattributable to the magnets, being equal in strength but differing insign, will add together when the subtraction is performed. Therefore the180° out of phase components, after being subtracted from each other,are divided by two. Removing or reducing fixed magnetic field effects isa significant advantage in that it improves system accuracy.

[2678] At least two of the measurements may be used to determine theEarth's magnetic field strength, B_(E). The Earth's magnetic fieldstrength along with measurements of inclination and azimuthal angle maybe used to give a “normal” directional survey. Use of all threemeasurements may determine the azimuthal angle between the wellbores,the radial distance between wellbores, and the initial distance alongthe z-axis of the first measurement location.

[2679] Simulations may be used to show the effects of spacing, L, on themagnetic field components produced from a wellbore with magnets andmeasured in a neighboring wellbore. FIGS. 438, 439, and 440 show themagnetic field components as a function of hole depth of neighboringobservation wellbores. B_(z) is the magnetic field component parallel tothe lengths of the wellbores, B_(r) is the magnetic field component in aperpendicular direction between the wellbores, and B_(Hsr) is theangular magnetic field component between the wellbores. In FIGS. 438,439, and 440, B_(Hsr) is zero because there was no angular offsetbetween the two wellbores. FIG. 438 shows the magnetic field componentswith a horizontal wellbore at 100 m depth and a neighboring observationwellbore at 90 m depth (i.e., 10 m wellbore spacing). The poles had amagnetic field strength of 1500 Gauss with a spacing, L, between thepoles of 10 m. The poles were placed from 0 meters to 250 m along thewellbore with a positive pole at 80 m. FIG. 439 shows the magnetic fieldcomponents with a horizontal wellbore at 100 m depth and a neighboringobservation wellbore at 95 m depth (i.e., 5 m wellbore spacing). TheB_(z) component begins to flatten as the wellbore spacing decreases.FIG. 440 shows the magnetic field components with a horizontal wellboreat 100 m depth and a neighboring observation wellbore at 97.5 m depth(i.e., 2.5 m wellbore spacing). The B_(z) component deviates more fromthe B_(r) component as the spacing between wellbores is furtherdecreased. FIGS. 438, 439, and 440 show that to be able to use theanalytical solution to monitor the magnetic field components, thespacing between poles, L, should typically be less than or about equalto the spacing between wellbores.

[2680] Further simulations determined the effect of build-up on themagnetic components (with a maximum turning of the wellbore of about 10°for every 30 m). Two wellbores both followed each other at a constantdistance. The wellbore with the magnets started at a set depth andmagnet location, and built angle (no turning) as the wellbore wasformed. The observation wellbore started at a depth 10 m from thewellbore with the magnets and offset 2 m from the magnet location, andalso built angle but at a slightly faster rate to keep the separationdistance about equal.

[2681]FIG. 441 shows the magnetic field components with the wellborewith magnets built at 4° per every 30 m and the observation wellborebuilt at 4.095° per every 30 m to maintain the well spacing. FIG. 441shows that the sine functions are only slightly skewed. The componentmaxima are no longer opposite the pole position (as shown in FIG. 438)because the wellbores are slightly offset and maintained at a constantdistance.

[2682]FIG. 442 depicts the ratio of B_(r)/B_(Hsr) from FIG. 441. In anideal situation, the ratio should be 5, since the observation wellborehas a separation in a perpendicular direction of 10 m from the wellborewith the magnets and an offset of 2 m (Hsr direction). The excessivepoints are due to the fact that the data for the excessive points aretaken at midpoints between the poles where both B_(r) and B_(Hsr) arezero.

[2683]FIG. 443 depicts the ratio of B_(r)/B_(Hsr) with a build-up of 10°per every 30 m. The distance between wellbores was the same as in FIG.442. FIG. 443 shows that the accuracy is still good for the highbuild-up rate. FIGS. 441-443 show that the accuracy of magnetic steeringis still relatively good for build-up sections of wellbores.

[2684]FIG. 444 depicts comparisons of actual calculated magnetic fieldcomponents versus magnetic field components modeled using analyticalequations for two parallel wellbores with L=20 m separation betweenpoles. FIG. 444 depicts the B_(z) component as a function of distancebetween the wellbores where a perfect fit (i.e., the difference betweenmodeling distance and actual distance is set at zero) is set at 7 m byadjusting the pole strengths, P. FIG. 445 depicts the difference betweenthe two curves in FIG. 444. As shown in FIGS. 444 and 445, the variationbetween the modeled and actual distance is relatively small and may bepredictable. FIG. 446 depicts the B_(r) component as a function ofdistance between the wellbores with the fit used for the perfect fit ofB_(z) set at 7 m. FIG. 447 depicts the difference between the two curvesin FIG. 446. FIGS. 444-447 show that the same accuracy exists usingB_(z) or B_(r) to determine distance.

[2685]FIG. 448 depicts a schematic representation of an embodiment of amagnetostatic drilling operation to form an opening that is anapproximate desired distance away from (e.g., substantially parallel to)a drilled opening. Opening 544 may be formed in hydrocarbon layer 522.In some embodiments, opening 544 may be formed in any hydrocarboncontaining formation, other types of subsurface formations, or for anysubsurface application (e.g., soil remediation, solution mining,steam-assisted gravity drainage (SAGD), etc.). Opening 544 may be formedsubstantially horizontally within hydrocarbon layer 522. For example,opening 544 may be formed substantially parallel to a boundary (e.g.,the surface) of hydrocarbon layer 522. Opening 544 may be formed inother orientations within hydrocarbon layer 522 depending on, forexample, a desired use of the opening, formation depth, a formationtype, etc. Opening 544 may include casing 3040. In certain embodiments,opening 544 may be an open (or uncased) wellbore. In some embodiments,magnetic string 3042 may be inserted into opening 544. Magnetic string3042 may be unwound from a reel into opening 544. In an embodiment,magnetic string 3042 includes one or more magnet segments 3044. In otherembodiments, magnetic string 3042 may include one or more movablepermanent longitudinal magnets. A movable permanent longitudinal magnetmay have a north and a south pole. Magnetic string 3042 may have alongitudinal axis that is substantially parallel (e.g., within about 5%of parallel) or coaxial with a longitudinal axis of opening 544.

[2686] Magnetic strings may be moved (e.g., pushed and/or pulled)through an opening using a variety of methods. In an embodiment, amagnetic string may be coupled to a drill string and moved through theopening as the drill string moves through the opening. Alternatively,magnetic strings may be installed using coiled tubing. Some embodimentsmay include coupling a magnetic string to a tractor system that movesthrough the opening. For example, commercially available tractor systemsfrom Welltec Well Technologies (Denmark) or Schlumberger Technology Co.(Houston, Tex.) may be used. In certain embodiments, magnetic stringsmay be pulled by cable or wireline from either end of an opening. In anembodiment, magnetic strings may be pumped through an opening using airand/or water. For example, a pig may be moved through an opening bypumping air and/or water through the opening and the magnetic string maybe coupled to the pig.

[2687] In some embodiments, casing 3040 may be a conduit. Casing 3040may be made of a material that is not significantly influenced by amagnetic field (e.g., non-magnetic alloy such as non-magnetic stainlesssteel (e.g., 304, 310, 316 stainless steel), reinforced polymer pipe, orbrass tubing). The casing may be a conduit of a conductor-in-conduitheater, or it may be perforated liner or casing. If the casing is notsignificantly influenced by a magnetic field, then the magnetic fluxwill not be shielded.

[2688] In other embodiments, the casing may be made of a ferromagneticmaterial (e.g., carbon steel). A ferromagnetic material may have amagnetic permeability greater than about 1. The use of a ferromagneticmaterial may weaken the strength of the magnetic field to be detected bydrilling apparatus 3046 in adjacent opening 3048. For example, carbonsteel may weaken the magnetic field strength outside of the casing(e.g., by a factor of 3 depending on the diameter, wall thickness,and/or magnetic permeability of the casing). Measurements may be madewith the magnetic string inside the carbon steel casing (or othermagnetically shielding casing) at the surface to determine the effectivepole strengths of the magnetic string when shielded by the carbon steelcasing. In certain embodiments, casing 3040 may not be used (e.g., foran open wellbore). Casing 3040 may not be magnetized, which allows theEarth's magnetic field to be used for other purposes (e.g., using acompass). Measurements of the magnetic field produced by magnetic string3042 in adjacent opening 3048 may be used to determine the relativecoordinates of adjacent opening 3048 to opening 544.

[2689] In some embodiments, drilling apparatus 3046 may include amagnetic guidance sensor probe. The magnetic guidance sensor probe maycontain a 3-axis fluxgate magnetometer and a 3-axis inclinometer. Theinclinometer is typically used to determine the rotation of the sensorprobe relative to the earth's gravitational field (i.e., the “toolfaceangle”). A general magnetic guidance sensor probe may be obtained fromTensor Energy Products (Round Rock, Tex.). The magnetic guidance sensormay be placed inside the drilling string coupled to a drill bit. Incertain embodiments, the magnetic guidance sensor probe may be locatedinside the drilling string of a river crossing rig.

[2690] Magnet segments 3044 may be placed within conduit 3050. Conduit3050 may be a threaded or seamless coiled tubular. Conduit 3050 may beformed by coupling one or more sections 3052. Sections 3052 may includenon-magnetic materials such as, but not limited to, stainless steel. Incertain embodiments, conduit 3050 is formed by coupling several threadedtubular sections. Sections 3052 may have any length desired (e.g., thesections may have a standard length for threaded tubulars). Sections3052 may have a length chosen to produce magnetic fields with selecteddistances between junctions of opposing poles in magnetic string 3042.The distance between junctions of opposing poles may determine thesensitivity of a magnetic steering method (i.e., the accuracy indetermining the distance between adjacent wellbores). Typically, thedistance between junctions of opposing poles is chosen to be on the samescale as the distance between adjacent wellbores (e.g., the distancebetween junctions may in a range of about 1 m to about 500 m or, in somecases, in a range of about 1 m to about 200 m).

[2691] In an embodiment, conduit 3050 is a threaded stainless steeltubular (e.g., a Schedule 40, 304 stainless steel tubular with anoutside diameter of about 7.3 cm (2.875 in.) formed from approximately 6m (20 ft.) long sections 3052). With approximately 6 m long sections3052, the distance between opposing poles will be about 6 m. In someembodiments, sections 3052 may be coupled as the conduit is formedand/or inserted into opening 544. Conduit 3050 may have a length betweenabout 125 m and about 175 m. Other lengths of conduit 3050 (e.g., lessthan about 125 m or greater than 175 m) may be used depending on adesired application of the magnetic string.

[2692] In an embodiment, sections 3052 of conduit 3050 may include twomagnet segments 3044. More or less than two segments may also be used insections 3052. Magnet segments 3044 may be arranged within sections 3052such that adjacent magnet segments have opposing polarities (i.e., thesegments are repelled by each other due to opposing poles (e.g., N-N) atthe junction of the segments), as shown in FIG. 448. In an embodiment,one section 3052 includes two magnet segments 3044 of opposingpolarities. The polarity between adjacent sections 3052 may be arrangedsuch that the sections have attracting polarities (i.e., the sectionsare attracted to each other due to attracting poles (e.g., S-N) at thejunction of the sections), as shown in FIG. 448. Arranging the opposingpoles approximate the center of each section may make assembly of themagnet segments within each section relatively easy. In an embodiment,the approximate centers of adjacent sections 3052 have opposite poles.For example, the approximate center of one section may have north polesand the adjacent section (or sections on each end of the one section)may have south poles as shown in FIG. 448.

[2693] Fasteners 3054 may be placed at the ends of sections 3052 to holdmagnet segments 3044 within the sections. Fasteners 3054 may include,but are not limited to, pins, bolts, or screws. Fasteners 3054 may bemade of non-magnetic materials. In some embodiments, ends of sections3052 may be closed off (e.g., end caps placed on the ends) to enclosemagnet segments 3044 within the sections. In certain embodiments,fasteners 3054 may also be placed at junctions of opposing poles ofadjacent magnet segments 3044 to inhibit the adjacent segments frommoving apart.

[2694]FIG. 449 depicts an embodiment of section 3052 with two magnetsegments 3044 with opposing poles. Magnet segments 3044 may include oneor more magnets 3056 coupled to form a single magnet segment. Magnetsegments 3044 and/or magnets 3056 may be positioned in a linear array.Magnets 3056 may be Alnico magnets or other types of magnets withsufficient magnetic strength to produce a magnetic field that can besensed in a nearby wellbore. Alnico magnets are made primarily fromalloys of aluminum, nickel and cobalt and may be obtained, for example,from Adams Magnetic Products, Co. (Elmhurst, Ill.). Using permanentmagnets in magnet segments 3044 may reduce the infrastructure associatedwith magnetic tracking compared to using inductive coils or magneticfield producing wires (e.g., there is no need to provide a current andthe infrastructure for providing current using permanent magnets). In anembodiment, magnets 3056 are Alnico magnets about 6 cm in diameter andabout 15 cm in length. Assembling a magnet segment from severalindividual magnets increases the strength of the magnetic field producedby the magnet segment. Increasing the strength of the magnetic field(s)produced by magnet segments may advantageously increase the maximumdistance for sensing the magnetic field(s). In certain embodiments, thepole strength of a magnet segment may be between about 100 Gauss andabout 2000 Gauss (e.g., about 1500 Gauss). In some embodiments, the polestrength of a magnet segment may be between about 1000 Gauss and about2000 Gauss. Magnets 3056 may be coupled with attracting poles coupledsuch that magnet segment 3044 is formed with a south pole at one end anda north pole at a second end. In one embodiment, 40 magnets 3056 ofabout 15 cm in length are coupled to form magnet segment 3044 of about 6m in length. Opposing poles of magnet segments 3044 may be alignedproximate the center of section 3052 as shown in FIGS. 448 and 449.Magnet segments may be placed within section 3052 and held within thesection with fasteners 3054. One or more sections 3052 may be coupled asshown in FIG. 448, to form a magnetic string.

[2695]FIG. 450 depicts a schematic of an embodiment of a portion ofmagnetic string 3042. Magnet segments 3044 may be positioned such thatadjacent segments have opposing poles. In some embodiments, force may beapplied to minimize distance 3058 between magnet segments 3044.Additional segments may be added to increase a length of magnetic string3042. In certain embodiments, magnet segments 3044 may be located withinsections 3052, as shown in FIG. 448. Magnetic strings may be coiledafter assembling. Installation of the magnetic string may includeuncoiling the magnetic string. Coiling and uncoiling of the magneticstring may also be used to change position of the magnetic stringrelative to a sensor in a nearby wellbore (e.g., drilling apparatus 3046in opening 3048 as shown in FIG. 448).

[2696] Magnetic strings may include multiple south-south and north-northopposing pole junctions. As shown in FIG. 450, the multiple opposingpole junctions may induce a series of magnetic fields 3060. Alternatingthe polarity of portions within a magnetic string may provide asinusoidal variation of the magnetic field along the length of themagnetic string. The magnetic field variations may allow for control ofthe desired spacing between drilled wellbores. In certain embodiments, aseries of magnetic fields 3060 may be sensed at greater distances thanindividual magnetic fields. Increasing the distance between opposingpole junctions within the magnetic string may increase the radialdistance at which a magnetometer may detect a magnetic field. In someembodiments, the distance between opposing pole junctions within themagnetic string may be varied. For example, more magnets may be used inportions proximate the earth's surface than in portions positioneddeeper in the formation.

[2697] In certain embodiments, the distance between junctions ofopposing poles of the magnetic strings may be increased or decreasedwhen the separation distance between two wellbores increases ordecreases, respectively. Shorter distances between junctions of opposingpoles increases the frequency of variations in the magnetic field, whichmay provide more guidance (i.e., better accuracy) to the drillingoperation for smaller wellbore separation distances. Longer distancesbetween junctions of opposing poles may be used to increase the overallmagnetic field strength for larger wellbore separation distances. Forexample, a distance between junctions of opposing poles of about 6 m mayinduce a magnetic field sufficient to allow drilling of adjacentwellbores at distances of less than about 16 m. In certain embodiments,the spacing between junctions of opposing poles may be varied betweenabout 3 m and about 24 m. In some embodiments, the spacing betweenjunctions of opposing poles may be varied between about 0.6 m and about60 m. The spacing between junctions of opposing poles may be varied toadjust the sensitivity of the drilling system (e.g., the allowedtolerance in spacing between adjacent wellbores).

[2698] In an embodiment, a magnetic string may be moved forward in afirst opening while forming an adjacent second opening using magnetictracking of the magnetic string. Moving the magnetic string forwardwhile forming the adjacent second opening may allow shorter lengths ofthe magnetic string to be used. Using shorter lengths of magnetic stringmay be more economically favorable by reducing material costs.

[2699] In one embodiment, a junction of opposing poles in the magneticstring (e.g., the junction of opposing poles at the center of themagnetic string) in the first opening may be aligned with the magneticsensor on a drilling string in the second opening. The second openingmay be drilled forward using magnetic tracking of the magnetic string.The second opening may be drilled forward a distance of about L/2, whereL is the spacing between junctions of opposing poles in the magneticstring. The magnetic string may then be moved forward a distance ofabout L/2. This process may be repeated until the second opening isformed at the desired length. The magnetic sensor may remained alignedwith the center of the magnetic string during the drilling process. Insome embodiments, the forward drilling and movement of the magneticstring may be done in increments of L/4.

[2700] In some embodiments, the strength of the magnets used may affectthe strength of the magnetic field induced. In certain embodiments, adistance between junctions of opposing poles of about 6 m may induce amagnetic field sufficient to drill adjacent wellbores at distances ofless than about 6 m. In other embodiments, a distance between junctionsof opposing poles of about 6 m may induce a magnetic field sufficient todrill adjacent wellbores at distances of less than about 10 m.

[2701] A length of the magnetic string may be based on an economicbalance between cost of the string and the cost of having to repositionthe string during drilling. A string length may range from about 20 m toabout 500 m. In an embodiment, a magnetic string may have a length ofabout 50 m. Thus, in some embodiments, the magnetic string may need tobe repositioned if the openings being drilled are longer than the lengthof the string.

[2702] In some embodiments, a magnet may be formed by one or moreinductive coils, solenoids, and/or electromagnets. FIG. 451 depicts anembodiment of a magnetic string. Magnetic string 3042 may include core3062. Core 3062 may be formed of ferromagnetic material (e.g., iron).Core 3062 may be surrounded by one or more coils 3064. Coils 3064 may bemade of conductive material (e.g., copper). Coils 3064 may include onecontinuous coil or several coils coupled together. In an embodiment,coils 3064 are wound in one direction (e.g., clockwise) for a specificlength and then the next specific length of coil is wound in a reversedirection (e.g., counter-clockwise). The specific length of coil woundin one direction may be equal to L/2, where L is the spacing betweenopposing poles as described above. Winding sections of coil in differentdirections may produce magnetic fields 3066, when an electrical currentis provided to coils 3064, that are oriented in opposite directions,thereby producing effective magnetic poles between the sections of coil.Alternating the directions of winding may also produce effectivemagnetic poles that are alternating between effective north poles andeffective south poles along a length of core 3062. Coupling section 3068may couple one or more sections of core 3062 together. Coupling section3068 may include non-ferromagnetic material (e.g., fiberglass orpolymer). Coupling section 3068 may be used to separate the opposingmagnetic poles.

[2703] An electrical current may be provided to coils 3064 to produceone or more magnetic fields (e.g., a series of magnetic fields) along alength of core 3062. The amount of electrical current provided to coils3064 may be adjusted to alter the strength of the produced magneticfields. The strength of the produced magnetic fields may be altered toadjust for the desired distance between wellbores (i.e., a strongermagnetic field for larger distances between wellbores, etc.). In certainembodiments, a direct current (DC) may be provided to coils 3064 in onedirection for a specified time (e.g., about 5 seconds to about 10seconds) and in a reverse direction for a specified time (e.g., about 5seconds to about 10 seconds). Measurements of the produced magneticfield with electrical current flowing in each direction may be taken.These measurements may be used to subtract or remove fixed magneticfields from the measurement of distance between wellbores.

[2704] When multiple wellbores are to be drilled around a centerwellbore, the center wellbore may be drilled and magnetic strings may beplaced in the center wellbore to guide the drilling of the otherwellbores substantially surrounding the center wellbore. Cumulativeerrors in drilling may be limited by drilling neighboring wellboresguided by the magnetic string. Additionally, only wellbores using themagnetic string may include a nonmagnetic liner, which may be moreexpensive than typical liners.

[2705] As an example, in a seven spot pattern, a first wellbore may beformed at the center of the well pattern. A magnetic string may beplaced in the first wellbore. The neighboring (or surrounding) sixwellbores may be formed using the magnetic string in the first wellborefor guidance. After the seven spot pattern has been formed, additionalwellbores may be formed by placing the magnetic string in one of the sixsurrounding wellbores and forming the nearest neighboring wellbores tothe wellbore with the magnetic string. The process of forming nearestneighboring wellbores and moving the magnetic string to form successiveneighboring wellbores may be repeated until a wellbore pattern has beenformed for a hydrocarbon containing formation. Drilling as many nearestneighbor wellbores as possible from a single wellbore may reduce thecost and time associated with moving the magnetic string from wellboreto wellbore and/or installing multiple magnetic strings.

[2706] In an embodiment, the nearest neighboring wellbores to apreviously formed wellbore are formed using magnetic steering with amagnetic string placed in the previously formed wellbore. The previouslyformed wellbore may have been formed by any standard drilling method(e.g., gyroscope, inclinometer, earth's field magnetometer, etc.) or bymagnetic steering from another previously formed wellbore. Formingnearest neighbor wellbores with magnetic steering may reduce the overalldeviation between wellbores in a well pattern formed for a hydrocarboncontaining formation. For example, the deviation between wellbores maybe kept below about ±1 m. In some embodiments of formed heaterwellbores, heat may be varied along the lengths of wellbores tocompensate for any variations in spacing between heater wellbores.

[2707] In certain embodiments, a magnetic guidance sensor probe may belocated inside a drilling string of a river crossing rig. River crossingrigs may be used to drill horizontal wellbores or substantiallyhorizontal wellbores through a hydrocarbon layer. In certainembodiments, river crossing rigs are used to drill angled wellboresthrough an overburden of a formation with a substantially horizontalwellbore in the hydrocarbon layer. River crossing rigs may also be usedto form wellbores in any subsurface formation or layer. FIG. 453 depictsan embodiment of an opening in a hydrocarbon containing formation thathas been formed with a river crossing rig. A wellbore (opening 544) maybe formed in hydrocarbon layer 522. Opening 544 may have first opening3070 at a first position on the surface and second opening 3072 at asecond position on the: surface at the other end of opening 544.Hydrocarbon layer 522 may have overburden 524. Portions of opening 544in overburden 524 may be enclosed in reinforcing material 3074.Reinforcing material 3074 may be cement or other suitable materials.Reinforcing material 3074 may inhibit heat or fluid losses to overburden524. Machinery 3076 may be located and used at first opening 3070 andmachinery 3078 may be located and used at second opening 3072.

[2708] Opening 544 may be formed in one or more steps. FIGS. 454-460depict an embodiment for forming opening 544 in a hydrocarbon containingformation. FIG. 454 depicts an embodiment for forming a portion ofopening 544 in overburden 524 at end of first opening 3070. Opening 544may be formed using machinery 3076. Machinery 3076 may include drillingequipment such as drill bits, drilling string, directional drillingequipment (e.g., a 3-axis fluxgate magnetometer and a 3-axisinclinometer), mud motor, etc. In some embodiments, drilling equipmentmay include a steerable cone, which can be pushed forward through thewellbore by a tubing injector and/or propel itself by vibration suchthat no drilling cuttings are generated in the wellbore. In forming awellbore with a river crossing rig, the drill bit of the river crossingrig may drill the wellbore at an angle as the drill bit entersoverburden 524 of the formation, as shown in FIG. 454. Drilling entryangles for river crossing rigs may vary between about 5° and about 20°with a typical angle of about 10° or about 12°.

[2709]FIG. 455 depicts an embodiment of reinforcing material 3074 placedin the portion of opening 544 in overburden 524 at end of first opening3070. After the portion of opening 544 in overburden 524 at end of firstopening 3070 has been formed, opening 544 may be reamed out andreinforcing material 3074 may be placed in the opening. In anembodiment, reinforcing material 3074 may be cement poured into opening544 and allowed to cure or harden. Reinforcing material 3074 may have athickness between about 0.5 cm and about 15 cm, between about 1 cm andabout 10 cm, or between about 2 cm and about 5 cm.

[2710]FIG. 456 depicts an embodiment for forming opening 544 inhydrocarbon layer 522 and overburden 524. After reinforcing material3074 is in place, opening 544 may be formed using machinery 3076. Drillbit 3080 may be used to form opening 544. Directional drilling may beused to guide the formation of opening 544. Directional drilling mayinclude the use of a 3-axis fluxgate magnetometer and a 3-axisinclinometer. Opening 544 may be formed between first opening 3070 at afirst position on the surface and second opening 3072 at a secondposition on the surface. Opening 544 may be drilled at the entry angleuntil a specified depth is reached (generally at some location inhydrocarbon layer 522 of the formation), at which depth the direction ofdrilling is changed to drill in a substantially horizontal directionthrough the formation. The substantially horizontal section of opening544 is drilled until the opening reaches a predetermined horizontallength. After the predetermined horizontal length is reached, thedirection of drilling is turned to an exit angle, which may besubstantially the same as the entry angle, to meet with machinery at thesecond end of the wellbore.

[2711]FIG. 457 depicts an embodiment of a reamed out portion of opening544 in overburden 524 at end of second opening 3072. A portion ofopening 544 in overburden 524 at end of second opening 3072 may bereamed out after forming opening 544. Reaming may be accomplished usingan attachment to drill bit 3080 or another device coupled to thedrilling string coupled to machinery 3076.

[2712]FIG. 458 depicts an embodiment of reinforcing material 3074 placedin the reamed out portion of opening 544 in overburden 524 at end ofsecond opening 3072. Reinforcing material 3074 may be placed in thereamed out portion of opening 544 in overburden 524 at end of secondopening 3072. Packer 3082 may be placed in the reamed out portion toinhibit reinforcing material from flowing into portions of opening 544in hydrocarbon layer 522.

[2713] After placement of reinforcing material 3074 in the reamed outportion, drill bit 3080 may reform opening 544 through the reinforcingmaterial and packer 3082, as shown in FIG. 459. After opening 544 hasbeen reformed, machinery at either the first end and/or the second endof the opening may be used to pull equipment into the wellbore. FIG. 460depicts an embodiment for installing equipment (e.g., heat sources,production conduits, etc.) into opening 544. In certain embodiments,machinery 3078 may be located at second opening 3072. Machinery 3078 mayinclude machinery for providing (i.e., insertion, unspooling, coupling,etc.) equipment 3084 to be installed in the wellbore. In one embodiment,machinery 3078 may include a coiled tubing rig for providing equipment3084 into opening 544. In an embodiment, equipment such as heaters orconduits may be fully assembled before being installed in opening 544(i.e., the equipment may be fully laid along the surface before beinginstalled). In certain embodiments, equipment 3084 may be pulled intoopening 544 with drill bit 3080 coupled to machinery 3076 at firstopening 3070. Pulling equipment (e.g., heaters or heat sources) into along horizontal wellbore may be more efficient than pushing theequipment into the wellbore.

[2714] In some embodiments, drill bit 3080 may be used to ream out thewellbore or increase the diameter of the wellbore as the drill bit ispulled into the opening. The wellbore may be reamed out either beforeequipment is pulled into the wellbore or, in some embodiments, asequipment is pulled into the wellbore. In certain embodiments, afterforming opening 544, a logging tool (e.g., a gyrolog) may be pulled backby coupling the logging tool to drill bit 3080 or to a pig coupled tomachinery 3076. The logging tool may be used to determine the accuracyin the formed location of opening 544. In other embodiments, magnetictracking may be used to determine the accuracy in the formed location ofopening 544.

[2715] River crossing rigs may provide an inexpensive and efficientmethod for forming a horizontal wellbore in a hydrocarbon layer. Thehorizontal wellbore may have a first opening at a first position on thesurface and a second opening at a second position on the surface. Rivercrossing rigs are operated by companies such as The Crossing CompanyInc. (Nisku, Alberta) or A&L Underground, Inc. (Lenexa, Kans.).

[2716] In some embodiments, a second wellbore with a first opening at afirst position on the surface and a second opening at a second positionon the surface may be formed using magnetic tracking of a first wellborewith a first opening at a first position and a second opening at asecond position. The first wellbore and/or the second wellbore may beformed using a river crossing rig or other equipment able to form awellbore with two entrances at the surface into a formation. The firstand second wellbores may be formed in any hydrocarbon containingformation, other types of subsurface formations, or for any subsurfaceapplication (e.g., soil remediation, solution mining, steam-assistedgravity drainage (SAGD), etc.).

[2717] A conduit may be installed in the wellbore (e.g., using the rivercrossing rig). The conduit may be a metal conduit that produces amagnetic field when a DC current is applied to the conduit. The magneticfield produced by the conduit may be used to guide the formation of thesecond wellbore at a desired spacing from the first wellbore. Amagnetometer, or other magnetic tracking device, in the second wellboremay be used to detect the magnetic field produced by the conduit. Aninclinometer may also be used to guide the forming of the secondwellbore relative to the first wellbore and/or the formation. Amagnetometer and/or an inclinometer may be placed at or near a drillstring used for forming the second wellbore. The conduit may be a casingplaced in the wellbore. For example, the conduit may be a heater casing.The conduit may also be a barrier conduit or conduit for propagating orconducting fluids to or out of the wellbore and/or formation.

[2718]FIG. 461 depicts an embodiment of an opening (wellbore) with aconduit that can be energized to produce a magnetic field. Opening 544may have first end 3070 at a first position on the surface and secondend 3072 at a second position on the surface. Conduit 3086 may beinstalled in opening 544. Conduit 3086 may include or be an electricalconductor. Conduit 3086 may be coated with insulated coating 3088. Insome embodiments, insulated coating 3088 may be placed on portions ofconduit 3086 in overburden 524 and/or in hydrocarbon layer 522.Insulated coating 3088 may be an epoxy, polymeric coating, asphaltcoating, materials used for cathodic protection of pipelines, or anyother suitable electro-insulating material. The insulated coating may besprayed on conduit 3086 or applied by any other suitable method.Insulated coating 3088 may reduce electrical losses to the formation.Reducing electrical losses tends to increase the accuracy of determiningthe position of the second wellbore. In addition, reducing electricallosses to the formation may increase the magnetic field strength and,thus, increase the range of sensing the magnetic field produced byconduit 3086 in hydrocarbon layer 522. In certain embodiments, insulatedcoating 3088 may melt, vaporize, and/or oxidize when heated to anelevated temperature during treatment of the formation.

[2719] Conduit 3086 may be electrically coupled to current source 3090at each end 3070, 3072 of opening 544. Each end of conduit 3086 may beelectrically coupled to current source 3090 with one or more electricalconductors 3092. Electrical conductors 3092 may be, for example, coppercables. Current source 3090 may provide current in a path from first end3070 towards second end 3072 and vice versa (e.g., by switching theleads of the current source or changing the polarity of the terminals onthe current source). In certain embodiments, current source 3090 is anarc welder power supply. Current source 3090 may be able to provide ahigh amperage DC current (e.g., a DC current of about 50 A or more).

[2720] In an embodiment, current source 3090 (e.g., an arc welder) maybe used to provide current to conduit 3086 to produce a magnetic fieldin hydrocarbon layer 522. The current may be measured during theenergizing cycles of the casing. The produced magnetic field may betracked to guide the forming (e.g., drilling) of a second wellbore inthe formation. In certain embodiments, current is provided from currentsource 3090 in one direction for a length of time (e.g., 5-10 seconds).The current is then provided in a reverse direction for a length of time(e.g., 5-10 seconds). The magnetic fields produced by both directions ofcurrent may be subtracted from each other to reduce the effects ofEarth's magnetic field on the measurement of the second wellborelocation.

[2721] In some embodiments, an insulated wire may be placed in theopening. The insulated wire may be coupled to a current source toproduce a magnetic field that is tracked for forming one or moreadditional openings. The results with the insulated wire may be comparedto the results using current flow through the casing to determinecurrent losses in the subsurface. For example, if the insulated wireindicates that the second wellbore is 6.1 meters away, and the currentflow through the casing indicates that the second wellbore is 6.7 metersfeet away, then subsequent measurements with the casing may bemultiplied by a calibration factor of 6.1/6.7.

[2722] In some embodiments, placing a cable in the opening may beavoided by making DC resistance measurements of the casing prior toand/or during installation into the ground. The DC resistancemeasurements of the casing can be compared to actual measurements of theDC resistance for the given length of casing. This comparison may yielda calibration factor that can be used in subsequent measurements.

[2723] One equation that may be used to determine the distance betweenwellbores is:

r=1/500×I/H;  (106)

[2724] where r is the radial distance between wellbores in meters; I isthe current in amperes; and H is the total magnetic field in Gauss. EQN.106 is true for a long length of wire (or casing) where the radialdistance from the wire is small in comparison to the length of the wire.EQN. 106 also assumes the that surface wires are sufficiently distantfrom the wire as compared to the distance between the two wellbores sothat surface wires negligibly affect the magnetic field between the twowellbores.

[2725] A more accurate calculation of the distances between wellboresmay be obtained by starting with the following equations:$\begin{matrix}{{B_{x} = {\frac{2\quad I}{c}\left\{ {\frac{y_{1}}{R_{1}^{2}} + \frac{D - y_{1}}{R_{2}^{2}}} \right\}}};} & (107) \\{{B_{y} = {\frac{2\quad I}{c}\left\{ {\frac{x_{1}}{R_{2}^{2}} + \frac{x_{1}}{R_{1}^{2}}} \right\}}};} & (108) \\{{R_{1}^{2} = {x_{1}^{2} + y_{1}^{2}}};{and}} & (109) \\{R_{2}^{2} = {x_{1}^{2} + {\left( {D - y_{1}} \right)^{2}.}}} & (110)\end{matrix}$

[2726] In EQNS. 107-110, B_(x) and B_(y) are the magnetic fields in thex- and y-directions; I is the current in A; and c is the speed of light.The variables: x₁; y₁; R₁; R₂; and D, are distances as shown in FIG.464. FIG. 464 depicts sensing wellbore 3094, surface magnetic fieldsource 3096, and tracked wellbore 3098. Tracked wellbore 3098 may have asource of a magnetic field inside the wellbore (e.g., a wireline orenergized casing). To determine x₁ and y₁, these equations areintroduced:

C _(x) =B _(x) cD/2I; and  (111)

C _(y) =B _(y) cD/2I.  (112)

[2727] Then the following simplifications are used: $\begin{matrix}{{u = {{{1/2}\left( {C_{x}^{2} + C_{y}^{2}} \right)} + \left\{ {{{1/4}\left( {C_{x}^{2} + C_{y}^{2}} \right)^{2}} - {2\left( {C_{x} - 2} \right)\left( {C_{x}^{2} + C_{y}^{2}} \right)}} \right\}^{1/2}}};\quad {and}} & (113) \\{v = {\left( {C_{x}^{2} + C_{y}^{2}} \right)^{1/2}{\left( {u - {2\quad C_{x}}} \right)^{1/2}.}}} & (114)\end{matrix}$

[2728] Solving for x₁ and y₁ using EQNS. 107-114 results in:$\begin{matrix}{{x_{1} = {{- {DC}_{y}}/v}};{and}} & (115) \\{y_{1} = {D{\left\{ {C_{x} - {\frac{1}{2}\left( {u - v} \right)}} \right\}/{v.}}}} & (116)\end{matrix}$

[2729] EQNS. 115 and 116 may be used to solve for the distances betweentwo wellbores as shown in FIG. 464.

[2730]FIG. 462 depicts a plan view of an embodiment of forming one ormore wellbores using magnetic tracking of a previously formed wellbore.Opening 544 may have been previously formed in the formation with firstend 3070 and second end 3072. Magnetic tracking of opening 544 may beused to form nearest neighbor openings 3100 and 3102. Opening 3100 mayhave first end 3104 at a first position on the surface and second end3108 at a second position on the surface. Opening 3102 may have firstend 3106 at a first position on the surface and second end 3110 at asecond position on the surface. Openings 3100 and 3102 may be formedusing one or more river crossing rigs. The river crossing rigs may havea drilling string that includes sensors for detecting the magnetic fieldproduced in opening 544. Openings 3100 and 3102 may be spaced atapproximate desired distances from opening 544. In certain embodiments,openings 3100 and 3102 may be formed at a substantially similar distancefrom opening 544 and/or substantially parallel to opening 544. Thespacing between opening 3100 and opening 544 (and the spacing betweenopening 3102 and opening 544) may be about 6 m in one embodiment. Insome embodiments, the spacing between opening 3100 and opening 544 maybe varied between about 1 m and about 35 m, or between about 3 m andabout 20 m.

[2731] In some embodiments, magnetic tracking of opening 544 may be usedto form openings 3112 and 3114 in the formation. Opening 3112 may havefirst end 3116 at a first position on the surface and second end 3118 ata second position on the surface. Opening 3114 may have first end 3120at a first position on the surface and second end 3122 at a secondposition on the surface. Openings 3112 and 3114 may be spaced at asubstantially similar distance from opening 544 and/or substantiallyparallel to opening 544. In an embodiment, openings 3112 and 3114 arespaced about 2 times the distance from opening 544 as openings 3100 and3102, respectively. In other embodiments, openings 3112 and 3114 may bespaced about 1.5 times, about 3 times, or about 4 times the distancefrom opening 544 as openings 3100 and 3102, respectively. In someembodiments, up to about 3, 4, or even 5 additional wellbores may beformed in one direction from a single wellbore using magnetic trackingof the single wellbore (e.g., opening 544). The number of wellbores thatmay be formed using magnetic tracking of a single wellbore may bedetermined by the produced magnetic field strength, the amount of themagnetic flux through the formation (which may be determined by themagnetic permeability of the formation), and/or the desired sensitivityin the placement and/or alignment of additional wellbores. In otherembodiments, conduits in one or more of openings 3100, 3102, 3112, and3114 may be used to produce a magnetic field that can be tracked to formadditional openings in the formation.

[2732]FIG. 463 depicts an embodiment of a wellbore with a conduit thatcan be energized to produce a magnetic field. Opening 544 may have oneopening at the surface of the formation. Conduit 3086 may be placed inopening 544. A portion of conduit 3086 may be coated with insulationlayer 3088. Insulation layer 3088 may inhibit electrical losses to theformation along the insulated length of conduit 3086. Current source3090 may be used to provide current to conduit 3086, as in theembodiment of FIGS. 461 and 462. The end of conduit 3086 that does notextend to the surface may be uninsulated, as shown in FIG. 463. Theuninsulated end may allow electrical current from conduit 3086 topropagate through the formation and return to current source 3090, asshown by the dashed current lines in FIG. 463. Magnetic fields producedby providing current to conduit 3086 may be tracked to form one or moreadditional openings in the formation.

[2733] In some embodiments, lead-in and lead-out conductors may be usedto couple conductors and/or conduits to a power source. Using lead-inand lead-out conductors may be less expensive than using coating and/orcladding of conductors or conduits in the overburden. Especially forrelatively large overburden depths (e.g., overburdens greater than about300 m in depth), using lead-in and lead-out conductors may be moreeconomically viable than using coating or cladding to reduce heat lossesin the overburden. FIG. 466 depicts an embodiment of a heat source witha conductor in a container. Conductor 1112 may be coupled to heatersupport 3126 with transition conductor 3128 at or near the junction ofoverburden 524 and hydrocarbon layer 522. Seal 3130 may be placed oncontainer 3132 at the junction of overburden 524 and hydrocarbon layer522 to enclose conductor 1112 in the conduit. Seal 3130 may includeelectrically insulating material to inhibit electrical conductionbetween container 3132 and conductor 1112 through the seal. Container3132 may be a conduit, a canister, or any other suitable vessel.Container 3132 may be made of corrosion resistant, electricallyconductive materials (e.g., stainless steel). In an embodiment,container 3132 is a 304 stainless steel container. Container 3132 may besealed and pressurized to withstand pressures in opening 544.

[2734] Lead-in conductor 3134 may be electrically coupled to conductor1112. Lead-in conductor 3134 may be used to supply electrical power toconductor 1112 from wellhead 3136. In an embodiment, lead-in conductor3134 may be coupled to conductor 1112 in container 3132. In oneembodiment, lead-in conductor 3134 is an insulated copper cable.Insulation for the copper cable may be a polymer such as neoprenerubber, nitrile rubber, silicone rubber, or fiberglass reinforcedsilicone, rubber, or glass fiber, etc. Feedthrough 3138 may allowlead-in conductor 3134 to pass through seal 3130. Feedthrough 3138 maybe any feedthrough that maintains a pressure seal around lead-inconductor 3134 (e.g., an o-ring seal, Swagelok® seal, etc.).

[2735] Lead-out conductor 3140 may be electrically coupled to container3132. Lead-out conductor 3140 may return electrical power from conductor1112 and container 3132 to wellhead 3136. In an embodiment, lead-outconductor 3140 is an insulated copper cable. Insulation for the coppercable may be a polymer such as neoprene rubber, nitrile rubber, siliconerubber, or fiberglass reinforced silicone, rubber, or glass fiber, etc.The electrical resistances of lead-in conductor 3134 and lead-outconductor 3140 may be relatively low to minimize heat losses in theoverburden.

[2736] In an embodiment, a sliding connector may be used to electricallycouple conduit 1176 to lead-out conductor 3140. FIG. 465 depicts anembodiment of a conductor-in-conduit heat source with a lead-outconductor coupled to a sliding connector. A second sliding connector3142 may be placed on (e.g., coupled to) conductor 1112 at or near thejunction of overburden 524 and hydrocarbon layer 522. Insulators 3144may be at contact points of second sliding connector 3142 with conductor1112 to inhibit electrical contact between the second sliding connectorand the conductor. Insulators 3144 may be ceramic insulators or anysuitable electrically insulating, thermally conductive material.

[2737] In an embodiment, lead-out conductor 3140 may be electricallycoupled to second sliding connector 3142 at or near the junction ofoverburden 524 and hydrocarbon layer 522. This sliding connector 3142may be electrically coupled to conduit 1176. Thus, electrical currentmay propagate from conduit 1176 through second sliding connector 3142and to lead-out conductor 3140. Transition conductor 3128 may couple lowresistance section 3146 to conductor 1112. Transition conductor 3128may, in some embodiments, include electrically insulating materials toelectrically isolate low resistance section 3146 from conductor 1112.Lead-in conductor 3134 may be coupled to conductor 1112 at or near thejunction of overburden 524 and hydrocarbon layer 522, as shown in FIG.465.

[2738] In some hydrocarbon containing formations (e.g., oil shaleformations), there may be one or more hydrocarbon layers characterizedby a significantly higher richness than other layers in the formation.These rich layers tend to be relatively thin (typically about 0.2 m toabout 0.5 m thick) and may be spaced throughout the formation. The richlayers generally have a richness of about 0.150 L/kg or greater. Somerich layers may have a richness greater than about 0.170 L/kg, greaterthan about 0.190 L/kg, or greater then about 0.210 L/kg. Other layers(i.e., relatively lean layers) of the formation may have a richness ofabout 0.100 L/kg or less and are generally thicker than rich layers. Therichness and locations of layers may be determined, for example, bycoring and subsequent Fischer assay of the core, density or neutronlogging, or other logging methods.

[2739]FIG. 467 depicts an embodiment of a heater in an open wellbore ofa hydrocarbon containing formation with a rich layer. Opening 544 may belocated in hydrocarbon layer 522. Hydrocarbon layer 522 may include oneor more rich layers 3148. Relatively lean layers 3150 in hydrocarbonlayer 522 may have a lower richness than rich layers 3148. Heater 3152may be placed in opening 544. In certain embodiments, opening 544 may bean open or uncased wellbore.

[2740] Rich layers 3148 may have a lower initial thermal conductivitythan other layers of the formation. Typically, rich layers 3148 have athermal conductivity 1.5 times to 3 times lower than the thermalconductivity of lean layers 3150. For example, a rich layer may have athermal conductivity of about 1.5×10⁻³ cal/cm·sec·° C. while a leanlayer of the formation may have a thermal conductivity of about 3.5×10⁻³cal/cm·sec·° C. In addition, rich layers 3148 may have a higher thermalexpansion coefficient than lean layers of the formation. For example, arich layer of 57 gal/ton (0.24 L/kg) oil shale may have a thermalexpansion coefficient of about 2.2×10⁻²%/° C. while a lean layer of theformation of about 13 gal/ton (0.05 L/kg) oil shale may have a thermalexpansion coefficient of about 0.63×10⁻²%/° C.

[2741] Because of the lower thermal conductivity in rich layers 3148,rich layers may become “hot spots” during heating of the formationaround opening 544. The “hot spots” may be generated because heatprovided from the heater in opening 544 does not transfer intohydrocarbon layer 522 as readily as through rich layers 3148 due to thelower thermal conductivity of the rich layers. Thus, the heat tends tostay at or near the wall of opening 544 during early stages of heating.

[2742] Material that expands from rich layers 3148 into the wellbore maybe significantly less stressed than material in the formation. Thermalexpansion and pyrolysis may cause additional fracturing and exfoliationof hydrocarbon material that expands into the wellbore. Thus, afterpyrolysis of expanded material in the wellbore, the expanded materialmay have an even lower thermal conductivity than pyrolyzed material inthe formation. Under low stress, pyrolysis may cause additionalfracturing and/or exfoliation of material, thus causing a decrease inthermal conductivity. The lower thermal conductivity may be caused bythe lower stress placed on pyrolyzed materials that have expanded intothe wellbore (i.e., pyrolyzed material that has expanded into thewellbore is no longer as stressed as the pyrolyzed material would be ifthe pyrolyzed material were still in the formation). This release ofstress tends to lower the thermal conductivity of the expanded,pyrolyzed material.

[2743] After the formation of “hot spots” at rich layers 3148,hydrocarbons in the rich layers will tend to expand at a much fasterrate than other layers of the formation due to increased heat at thewall of the wellbore and the higher thermal expansion coefficient of therich layers. Expansion of the formation into the wellbore may reduceradiant heat transfer to the formation. The radiant heat transfer may bereduced for a number of reasons, including, but not limited to, materialcontacting the heater, thus stopping radiant heat transfer; andreduction of wellbore radius which limits the surface area that radiantheat is able to transfer to. Reduction of radiant heat transfer mayresult in higher heater temperature adjacent to areas with reducedradiant heat transfer acceptance capability.

[2744] Rich layers 3148 may expand at a much faster rate than leanlayers because of the significantly lower thermal conductivity of richlayers and/or the higher thermal expansion coefficient of the richlayers. The expansion may apply significant pressure to a heater whenthe wellbore closes off against the heater. The wellbore closing off, orsubstantially closing off against the heater may also inhibit flow offluids between layers of the formation. In some embodiments, fluids maybecome trapped in the wellbore because of the closing off or substantialclosing off of the wellbore against the heater.

[2745]FIG. 468 depicts an embodiment of heater 3152 in opening 544 withexpanded rich layer 3148. In some embodiments, opening 544 may be closedoff by the expansion of rich layer 3148, as shown in FIG. 468, (i.e., anannular space between the heater and wall of the opening may be closedoff by expanded material). Closing off of the annulus of the opening maytrap fluids between expanded rich layers in the opening. The trapping offluids can increase pressures in the opening beyond desirable limits. Insome circumstances, the increased pressure could cause fracturing of theformation or in the heater well that would allow fluid to unexpectedlybe in communication with an opening from the formation. In somecircumstances, the increased pressure may exceed a deformation pressureof the heater. Deformation of the heater may also be caused by theexpansion of material from the rich layers against the heater.Deformation of the heater may cause the heater to shut down or fail.Thus, the expansion of material in rich layers may need to be reducedand/or deformation of a heater in the opening may need to be inhibitedso that the heater operates properly.

[2746] A significant amount of the expansion of rich layers tends tooccur during early stages of heating (e.g., often within the first 15days or 30 days of heating at a heat injection rate of about 820watts/meter). Typically, a majority of the expansion occurs below about200° C. in the near wellbore region. For example, a 0.189 L/kg oil shalelayer will expand about 5 cm up to about 200° C. depending on factorssuch as, but not limited to, heating rate, formation stresses, andwellbore diameter. Methods for compensating for the expansion of richlayers of a formation may be focused on in the early stages of an insitu process. The amount of expansion during or after heating of theformation may be estimated or determined before heating of the formationbegins. Thus, allowances may be made to compensate for the thermalexpansion of rich layers and/or lean layers in the formation. The amountof expansion caused by heating of the formation may be estimated basedon factors such as, but not limited to, measured or estimated richnessof layers in the formation, thermal conductivity of layers in theformation, thermal expansion coefficients (e.g., linear thermalexpansion coefficient) of layers in the formation, formation stresses,and expected temperature of layers in the formation.

[2747]FIG. 469 depicts simulations (using a reservoir simulator (STARS)and a mechanical simulator (ABAQUS)) of wellbore radius change versustime for heating of a 20 gal/ton oil shale (0.084 L/kg oil shale) in anopen wellbore for a heat output of 820 watts/meter (plot 3149) and aheat output of 1150 watts/meter (plot 3151). As shown in FIG. 469, themaximum expansion of a 20 gal/ton oil shale increases from about 0.38 cmto about 0.48 cm for increased heat output from 820 watts/meter to 1150watts/meter. FIG. 470 depicts calculations of wellbore radius changeversus time for heating of a 50 gal/ton oil shale (0.21 L/kg oil shale)in an open wellbore for a heat output of 820 watts/meter (plot 3153) anda heat output of 1150 watts/meter (plot 3155). As shown in FIG. 470, themaximum expansion of a 50 gal/ton oil shale increases from about 8.2 cmto about 10 cm for increased heat output from 820 watts/meter to 1150watts/meter. Thus, the expansion of the formation depends on therichness of the formation, or layers of the formation, and the heatoutput to the formation.

[2748] In one embodiment, opening 544 may have a larger diameter toinhibit closing off of the annulus after expansion of rich layers 3148.A typical opening may have a diameter of about 16.5 cm. In certainembodiments, heater 3152 may have a diameter of about 7.3 cm. Thus,about 4.6 cm of expansion of rich layers 3148 will close off theannulus. If the diameter of opening 544, is increased to about 30 cm,then about 11.3 cm of expansion would be needed to close off theannulus. The diameter of opening 544 may be chosen to allow for acertain amount of expansion of rich layers 3148. In some embodiments, adiameter of opening 544 may be greater than about 20 cm, greater thanabout 30 cm, or greater than about 40 cm. Larger openings or wellboresalso may increase the amount of heat transferred from the heater to theformation by radiation. Radiative heat transfer may be more efficientfor transfer of heat within the opening. The amount of expansionexpected from rich layers 3148 may be estimated based on richness of thelayers. The diameter of opening 544 may be selected to allow for themaximum expansion expected from a rich layer so that a minimum spacebetween a heater and the formation is maintained after expansion.Maintaining a minimum space between a heater and the formation mayinhibit deformation of the heater caused by the expansion of materialinto the opening. In an embodiment, a desired minimum space between aheater and the formation after expansion may be at least about 0.25 cm,0.5 cm, or 1 cm. In some embodiments, a minimum space may be at leastabout 1.25 cm or at least about 1.5 cm, and may range up to about 3 cm,about 4 cm, or about 5 cm.

[2749] In some embodiments, opening 544 may be expanded proximate richlayers 3148, as depicted in FIG. 471, to maintain a minimum spacebetween a heater and the formation after expansion of the rich layers.Opening 544 may be expanded proximate rich layers by underreaming of theopening. For example, an eccentric drill bit, an expanding drill bit, orhigh-pressure water jet abrasion may be used to expand an openingproximate rich layers. Opening 544 may be expanded beyond the edges ofrich layers 3148 so that some material from lean layers 3150 is alsoremoved. Expanding opening 544 with overlap into lean layers 3150 mayfurther allow for expansion and/or any possible indeterminations in thedepth or size of a rich layer.

[2750] In another embodiment, heater 3152 may include sections 3154 thatprovide less heat output proximate rich layers 3148 than sections 3156that provide heat to lean layers 3150, as shown in FIG. 471. Section3154 may provide less heat output to rich layers 3148 so that the richlayers are heated at a lower rate than lean layers 3150. Providing lessheat to rich layers 3148 will reduce the wellbore temperature proximatethe rich layers, thus reducing the total expansion of the rich layers.In an embodiment, heat output of sections 3154 may be about one half ofheat output from sections 3156. In some embodiments, heat output ofsections 3154 may be less than about three quarters, less than about onehalf, or less than about one third of heat output of sections 3156.Generally, a heating rate of rich layers 3148 may be lowered to a heatoutput that limits the expansion of rich layers 3148 so that a minimumspace between heater 3152 and rich layers 3148 in opening 544 ismaintained after expansion. Heat output from heater 3152 may becontrolled to provide lower heat output proximate rich layers. In someembodiments, heater 3152 may be constructed or modified to provide lowerheat output proximate rich layers. Examples of such heaters includeheaters with temperature limiting characteristics, such as Curietemperature heaters, tailored heaters with less resistive sectionsproximate rich layers, etc.

[2751] In some embodiments, opening 544 may be reopened after expansionof rich layers 3148 (e.g., after about 15 to 30 days of heating at 820Watts/m). Material from rich layers 3148 may be allowed to expand intoopening 544 during heating of the formation with heater 3152, as shownin FIG. 468. After expansion of material into opening 544, an annulus ofthe opening may be reopened, as shown in FIG. 467. Reopening the annulusof opening 544 may include over washing the opening after expansion witha drill bit or any other method used to remove material that hasexpanded into the opening.

[2752] In certain embodiments, pressure tubes (e.g., capillary pressuretubes) may be coupled to the heater at varying depths to assess ifand/or when material from the formation has expanded and sealed theannulus. In some embodiments, comparisons of the pressures at varyingdepths may be used to determine when an opening should be reopened.

[2753] In certain embodiments, rich layers 3148 and/or lean layers 3150may be perforated. Perforating rich layers 3148 and/or lean layers 3150may allow expansion of material within these layers and inhibit orreduce expansion into opening 544. Small holes may be formed into richlayers 3148 and/or lean layers 3150 using perforation equipment (e.g.,bullet or jet perforation). Such holes may be formed in both casedwellbores and open wellbores. These small holes may have diameters lessthan about 1 cm, less than about 2 cm, or less than about 3 cm. In someembodiments, larger holes may also be formed. These holes may bedesigned to provide, or allow, space for the formation to expand. Theholes may also weaken the rock matrix of a formation so that if theformation does expand, the formation will exert less force. In someembodiments, the formation may be fractured instead of using aperforation gun.

[2754] In certain embodiments, a liner or casing may be placed in anopen wellbore to inhibit collapse of the wellbore during heating of theformation. FIG. 472 depicts an embodiment of a heater in an openwellbore with a liner placed in the opening. Liner 3158 may be placed inopening 544 in hydrocarbon layer 522. Liner 3158 may include firstsections 3160 and second sections 3162. First sections 3160 may belocated proximate lean layers 3150. Second sections 3162 may be locatedproximate rich layers 3148. Second sections 3162 may be thicker thanfirst sections 3160. Additionally, second sections 3162 may be made of astronger material than first sections 3160.

[2755] In one embodiment, first sections 3160 are carbon steel with athickness of about 2 cm and second sections 3162 are Haynes® HR-120®(available from Haynes International Inc. (Kokomo, Ind.)) with athickness of about 4 cm. The thicknesses of first sections 3160 andsecond sections 3162 may be varied between about 0.5 cm and about 10 cm.The thicknesses of first sections 3160 and second sections 3162 may beselected based upon factors such as, but not limited to, a diameter ofopening 544, a desired thermal transfer rate from heater 3152 tohydrocarbon layer 522, and/or a mechanical strength required to inhibitcollapse of liner 3158. Other materials may also be used for firstsections 3160 and second sections 3162. For example, first sections 3160may include, but may not be limited to, carbon steel, stainless steel,aluminum, etc. Second sections 3162 may include, but may not be limitedto, 304H stainless steel, 316H stainless steel, 347H stainless steel,Incoloy® alloy 800H or Incoloy® alloy 800HT (both available from SpecialMetals Co. (New Hartford, N.Y.)), etc.

[2756]FIG. 473 depicts an embodiment of a heater in an open wellborewith a liner placed in the opening and the formation expanded againstthe liner. Second sections 3162 may inhibit material from rich layers3148 from closing off an annulus of opening 544 (between liner 3158 andheater 3152) during heating of the formation. Second sections 3162 mayhave a sufficient strength to inhibit or slow down the expansion ofmaterial from rich layers 3148. One or more openings 3164 may be placedin liner 3158 to allow fluids to flow from the annulus between liner3158 and the walls of opening 544 into the annulus between the liner andheater 3152. Thus, liner 3158 may maintain an open annulus between theliner and heater 3152 during expansion of rich layers 3148 so thatfluids can continue to flow through the annulus. Maintaining a fluidpath in opening 544 may inhibit a buildup of pressure in the opening.Second sections 3162 may also inhibit closing off of the annulus betweenliner 3158 and heater 3152 so that hot spot formation is inhibited, thusallowing the heater to operate properly.

[2757] In some embodiments, conduit 3166 may be placed inside opening544 as shown in FIGS. 472 and 473. Conduit 3166 may include one or moreopenings for providing a fluid to opening 544. In an embodiment, steammay be provided to opening 544. The steam may inhibit coking in openings3164 along a length of liner 3158, such that openings are not cloggedand fluid flow through the openings is maintained. In certainembodiments, conduit 3166 may be placed inside liner 3158. In otherembodiments, conduit 3166 may be placed outside liner 3158. Conduit 3166may also be permanently placed in opening 544 or may be temporarilyplaced in the opening (e.g., the conduit may be spooled and unspooledinto an opening). Conduit 3166 may be spooled and unspooled into anopening so that the conduit can be used in more than one opening in aformation.

[2758]FIG. 474 depicts maximum radial stress 3163, maximumcircumferential stress 3165, and hole size 3167 after 300 days versusrichness for calculations of heating in an open wellbore. Thecalculations were done with a reservoir simulator (STARS) and amechanical simulator (ABAQUS) for a 16.5 cm wellbore with a 14.0 cmliner placed in the wellbore and a heat output from the heater of 820watts/meter. As shown in FIG. 474, the maximum radial stress and maximumcircumferential stress decrease with richness. Layers with a richnessabove about 22.5 gal/ton (0.95 L/kg) may expand to contact the liner. Asthe richness increases above about 32 gal/ton (0.13 L/kg), the maximumstresses begin to somewhat level out at a value of about 270 barsabsolute or below. The liner may have sufficient strength to inhibitdeformation at the stresses above richnesses of about 32 gal/ton.Between about 22.5 gal/ton richness and about 32 gal/ton richness, thestresses may be significant enough to deform the liner. Thus, thediameter of the wellbore, the diameter of the liner, the wall thicknessand strength of the liner, the heat output, etc. may have to be adjustedso that deformation of the liner is inhibited and an open annulus ismaintained in the wellbore for all richnesses of a formation.

[2759] During early periods of heating a hydrocarbon containingformation, the formation may be susceptible to geomechanical motion.Geomechanical motion in the formation may cause deformation of existingwellbores in a formation. If significant deformation of wellbores occursin a formation, equipment (e.g., heaters, conduits, etc.) in thewellbores may be deformed and/or damaged.

[2760] Geomechanical motion is typically caused by heat provided fromone or more heaters placed in a volume in the formation that results inthermal expansion of the volume. The thermal expansion of a volume maybe defined by the equation:

Δr=r×ΔT×α;  (117)

[2761] where r is the radius of the volume (i.e., r is the length of thelongest straight line in a footprint of the volume that has continuousheating, as shown in FIGS. 475 and 476), ΔT is the change intemperature, and a is the linear thermal expansion coefficient.

[2762] The amount of geomechanical motion generally increases as moreheat is input into the formation. Geomechanical motion in the formationand wellbore deformation tend to increase as larger volumes of theformation are heated at a particular time. Therefore, if the volumeheated at a particular time is maintained in selected size limits, theamount of geomechanical motion and wellbore deformation may bemaintained below acceptable levels. Also, geomechanical motion in afirst treatment area may be limited by heating a second treatment areaand a third treatment area on opposite sides of the first treatmentarea. Geomechanical motion caused by heating the second treatment areamay be offset by geomechanical motion caused by heating the thirdtreatment area.

[2763]FIG. 475 depicts an embodiment of an aerial view of a pattern ofheaters for heating a hydrocarbon containing formation. Heat sources3168 may be placed in formation 3170. Heat sources 3168 may be placed ina triangular pattern, as depicted in FIG. 475, or any other pattern asdesired. Formation 3170 may include one or more volumes 3172, 3174 to beheated. Volumes 3172, 3174 may be alternating volumes of formation 3170as depicted in FIG. 475. In some embodiments, heat sources 3168 involumes 3172, 3174 may be turned on, or begin heating, substantiallysimultaneously (i.e., heat sources 3168 may be turned on within days or,in some cases, within 1 or 2 months of each other). Turning on all heatsources 3168 in volumes 3172, 3174 may, however, cause significantamounts of geomechanical motion in formation 3170. This geomechanicalmotion may deform the wellbores of one or more heat sources 3168 and/orother wellbores in the formation. The outermost wellbores in formation3170 may be most susceptible to deformation. These wellbores may be moresusceptible to deformation because geomechanical motion tends to be acumulative effect, increasing from the center of a heated volume towardsthe perimeter of the heated volume.

[2764]FIG. 476 depicts an embodiment of an aerial view of anotherpattern of heaters for heating a hydrocarbon containing formation.Volumes 3172, 3174 may be concentric rings of volumes, as shown in FIG.476. Heat sources 3168 may be placed in a desired pattern or patterns involumes 3172, 3174. In a concentric ring pattern of volumes 3172, 3174,the geomechanical motion may be reduced in the outer rings of volumesbecause of the increased circumference of the volumes as the rings moveoutward.

[2765] In other embodiments, volumes 3172, 3174 may have other footprintshapes and/or be placed in other shaped patterns. For example, volumes3172, 3174 may have linear, curved, or irregularly shaped stripfootprints. In some embodiments, volumes 3174 may separate volumes 3172and thus be used to inhibit geomechanical motion in volumes 3172 (i.e.,volumes 3114 may function as a barrier (e.g., a wall) to reduce theeffect of geomechanical motion of one volume 3172 on another volume3172).

[2766] In certain embodiments, heat sources 3168 in volumes 3172, 3174,as shown in FIGS. 475 and 476, may be turned on at different times toavoid heating large volumes of the formation at one time and/or toreduce the effects of geomechanical motion. In one embodiment, heatsources 3168 in volumes 3172 may be turned on, or begin heating, atsubstantially the same time (i.e., within 1 or 2 months of each other).Heat sources 3168 in volumes 3174 may be turned off while volumes 3172are being heated. Heat sources 3168 in volumes 3174 may be turned on, orbegin heating, a selected time after heat sources 3168 in volumes 3172are turned on or begin heating. Providing heat to only volumes 3172 fora selected period of time may reduce the effects of geomechanical motionin the formation during a selected period of time. During the selectedperiod of time, some geomechanical motion may take place in volumes3172. The size, as well as shape and/or location, of volumes 3172 may beselected to maintain the geomechanical expansion of the formation inthese volumes below a maximum value. The maximum value of geomechanicalexpansion of the formation may be a value selected to inhibitdeformation of one or more wellbores beyond a critical value ofdeformation (i.e., a point at which the wellbores are damaged orequipment in the wellbores is no longer useable).

[2767] The size, shape, and/or location of volumes 3172 may bedetermined by simulation, calculation, or any suitable method forestimating the extent of geomechanical motion during heating of theformation. In one embodiment, simulations may be used to determine theamount of geomechanical motion that may take place in heating a volumeof a formation to a predetermined temperature. The size of the volume ofthe formation that is heated to the predetermined temperature may bevaried in the simulation until a size of the volume is found thatmaintains any deformation of a wellbore below the critical value.

[2768] Sizes of volumes 3172, 3174, may be represented by a footprintarea on the surface of a volume and the depth of the portion of theformation contained in the volume. The sizes of volumes 3172, 3174 maybe varied by varying footprint areas of the volumes. In an embodiment,the footprints of volumes 3172, 3174 may be less than about 10,000square meters, less than about 6000 square meters, less than about 4000square meters, or less than about 3000 square meters.

[2769] Expansion in a formation may be zone, or layer, specific. In someformations, layers or zones of the formation may have different thermalconductivities and/or different thermal expansion coefficients. Forexample, an oil shale formation may have certain thin layers (e.g.,layers having a richness above about 0.15 L/kg) that have lower thermalconductivities and higher thermal expansion coefficients than adjacentlayers of the formation. The thin layers with low thermal conductivitiesand high thermal conductivities may lie within different horizontalplanes of the formation. The differences in the expansion of thin layersmay have to be accounted for in determining the sizes of volumes of theformation that are to be heated. Generally, the largest expansion may befrom zones or layers with low thermal conductivities and/or high thermalexpansion coefficients. In some embodiments, the size, shape, and/orlocation of volumes 3172, 3174 may be determined to accommodateexpansion characteristics of low thermal conductivity and/or highthermal expansion layers.

[2770] In some embodiments, the size, shape, and/or location of volumes3174 may be selected to inhibit cumulative geomechanical motion fromoccurring in the formation. In certain embodiments, volumes 3174 mayhave a volume sufficient to inhibit cumulative geomechanical motion fromeffecting spaced apart volumes 3172. In one embodiment, volumes 3174 mayhave a footprint area substantially similar to the footprint area ofvolumes 3172. Having volumes 3172, 3174 of substantially similar sizemay establish a uniform heating profile in the formation.

[2771] In certain embodiments, heat sources 3168 in volumes 3174 may beturned on at a selected time after heat sources 3168 in volumes 3172have been turned on. Heat sources 3168 in volumes 3174 may be turned on,or begin heating, within about 6 months (or within about 1 year or about2 years) from the time heat sources 3168 in volumes 3172 begin heating.Heat sources 3168 in volumes 3174 may be turned on after a selectedamount of expansion has occurred in volumes 3172. In one embodiment,heat sources 3168 in volumes 3174 are turned on after volumes 3172 havegeomechanically expanded to or nearly to their maximum possibleexpansion. For example, heat sources 3168 in volumes 3174 may be turnedon after volumes 3172 have geomechanically expanded to greater thanabout 70%, greater than about 80%, or greater than about 90% of theirmaximum estimated expansion. The estimated possible expansion of avolume may be determined by a simulation, or other suitable method, asthe expansion that will occur in a volume when the volume is heated to aselected average temperature. Simulations may also take into effectstrength characteristics of a rock matrix. Strong expansion in aformation occurs up to typically about 200° C. Expansion in theformation is generally much slower from about 200° C. to about 350° C.At temperatures above retorting temperatures, there may be little or noexpansion in the formation. In some formations, there may be compactionof the formation above retorting temperatures. The average temperatureused to determine estimated expansion may be, for example, a maximumtemperature that the volume of the formation is heated to during in situtreatment of the formation (e.g., about 325° C., about 350° C., etc.).Heating volumes 3174 after significant expansion of volumes 3172 occursmay reduce, inhibit, and/or accommodate the effects of cumulativegeomechanical motion in the formation.

[2772] In some embodiments, heat sources 3168 in volumes 3174 may beturned on after heat sources 3168 in volumes 3172 at a time selected tomaintain a relatively constant production rate from the formation.Maintaining a relatively constant production rate from the formation mayreduce costs associated with equipment used for producing fluids and/ortreating fluids produced from the formation (e.g., purchasing equipment,operating equipment, purchasing raw materials, etc.). In certainembodiments, heat sources 3168 in volumes 3174 may be turned on afterheat sources 3168 in volumes 3172 at a time selected to enhance aproduction rate from the formation. Simulations, or other suitablemethods, may be used to determine the relative time at which heatsources 3168 in volumes 3172 and heat sources 3168 in volumes 3174 areturned on to maintain a production rate, or enhance a production rate,from the formation.

[2773] In certain embodiments, a “temperature limited heater” may beused to provide heat to a hydrocarbon containing formation. Atemperature limited heater generally refers to a heater that regulatesheat output (e.g., reduces heat output) above a specified temperaturewithout the use of external controls such as temperature controllers,power regulators, etc. Temperature limited heaters may be AC(alternating current) electrical resistance heaters. Temperature limitedheaters may be more reliable than other heaters. Temperature limitedheaters may be less apt to break down or fail due to hot spots in theformation. In some embodiments, temperature limited heaters may allowfor substantially uniform heating of a formation. In some embodiments,temperature limited heaters may be able to heat a formation moreefficiently by operating at a higher temperature along the entire lengthof the heater. The temperature limited heater may be operated at thehigher temperature along the entire length of the heater because powerto the heater does not have to be reduced to the entire heater (e.g.,along the entire length of the heater), as is the case with typicalheaters, if a temperature along any point of the heater exceeds, or isabout to exceed, a maximum operating temperature of the heater. Portionsof a temperature limited heater approaching a maximum operatingtemperature of the heater may self-regulate to reduce the heat outputonly in those portions when a limiting temperature of the heater isreached. Thus, a constant power (e.g., a constant current) may besupplied to the temperature limited heater during a larger portion of aheating process.

[2774] In some embodiments, a temperature limited heater may includeswitches (e.g., fuses, thermostats, etc.) that turn off power to aheater or portions of the heater when a temperature limit in the heateris reached. Other temperature limited heaters may use certain materialsin the heater that are inherently temperature limited at certaintemperatures. For example, ferromagnetic materials may be used intemperature limited heater embodiments. Ferromagnetic materials mayself-regulate at or near the Curie temperature of the material toprovide a reduced heat output at or near the Curie temperature. Usingferromagnetic materials in temperature limited heaters may be lessexpensive and more reliable than using switches in temperature limitedheaters.

[2775] The Curie temperature is the temperature above which a magneticmaterial (e.g., ferromagnetic material) loses its magnetic properties. Aheater may include a conductor that operates as a skin effect heaterwhen alternating current is applied to the conductor. The skin effectlimits the depth of current penetration into the interior of theconductor. For ferromagnetic materials, the skin effect is dominated bythe magnetic permeability of the conductor. The magnetic permeability offerromagnetic materials is typically greater than 1, and may be greaterthan 10, 100, or even 1000. As the temperature of the ferromagneticmaterial is raised above the Curie temperature, the magneticpermeability of the ferromagnetic material decreases substantially andthe skin depth expands rapidly (e.g., as the inverse square root of themagnetic permeability). This reduction in magnetic permeability resultsin a decrease in the AC resistance of the conductor above the Curietemperature. When the heater is powered by a substantially constantcurrent source, portions of the heater that reach the Curie temperaturewill have reduced power dissipation. Sections of the heater that are notat or near the Curie temperature may be dominated by skin effect heatingthat allows the heater to maintain a substantially constant heatdissipation rate.

[2776] Heating apparatus that utilize Curie temperature have been usedin equipment for soldering, used in medical applications, and used inheating of ovens (e.g., pizza ovens). Some of these uses are disclosedin U.S. Pat. Nos. 5,579,575 to Lamome et al.; 5,065,501 to Henschen etal.; and 5,512,732 to Yagnik et al., all of which are incorporated byreference as if fully set forth herein. U.S. Pat. No. 4,849,611 toWhitney et al., which is incorporated by reference as if fully set forthherein, describes a plurality of discrete, spaced-apart heating unitsincluding a reactive component, a resistive heating component, and atemperature responsive component.

[2777] An advantage of a Curie temperature heater for heating ahydrocarbon containing formation may be that the conductor can be chosento have a Curie temperature within a desired range of temperatureoperation. The desired operating range may allow for substantial heatinjection into the formation while maintaining the temperature of theheater, and other equipment, below design temperatures (i.e., belowtemperatures that will adversely affect properties such as corrosion,creep, deformation, etc.). In certain embodiments, formation temperaturemay be increased to within 15%, within 10%, or within 5% of a failuretemperature of a heater. The self-regulating properties of the heatermay inhibit overheating of low thermal conductivity “hot spots” in theformation.

[2778] A Curie temperature heater may allow for more heat injection intoa formation than for non-self regulating heaters because the energyinput into the heater does not have to be limited to accommodate thermalexpansion considerations for thin low thermal conductivity regionsadjacent to the heater. For example, in an oil shale formation in thePiceance basin of western Colorado there is a difference of at least 50%in the thermal conductivity of the lowest richness oil shale layers(less than about 0.04 L/kg) and the highest richness oil shale layers(greater than about 0.20 L/kg). When heating such a formation,substantially more heat may be injected with a temperature limitedheater than with a heater that is limited by the temperature at therichest lowest thermal conductivity layer, which may be only about 0.3 mthick. Because heaters for heating hydrocarbon formations typically havelong lengths (e.g., greater than 10 m, 50 m, or 100 m), the majority ofthe length of the heater may be operating substantially below the Curietemperature while only a few portions are self-regulating substantiallynear the Curie temperature.

[2779] The use of Curie temperature heaters may allow for efficienttransfer of heat to a formation. The efficient transfer of heat mayallow for reduction in time needed to heat a formation to a desiredtemperature. For example, in the Piceance basin oil shale, pyrolysis mayrequire about 9.5 to about 10 years of heating when using about a 12 mheater well spacing with conventional constant wattage heaters. Usingthe same spacing, Curie temperature heaters may permit greater averageheat output without heating above equipment design temperatures, therebyallowing pyrolysis in, for example, about 5 years.

[2780] The use of temperature limited heaters may eliminate or reducethe need to perform temperature logging and/or use fixed thermocoupleson the heaters to inhibit overheating at hot spots. The temperaturelimited heater also may eliminate or reduce the need for expensivetemperature control circuitry.

[2781] A temperature limited heater may be deformation tolerant iflocalized movement of a wellbore results in lateral stresses on theheater that could deform its shape. Locations at which the wellbore hasclosed on the heater and deformed the heater also tend to be hot spotswhere a standard heater may overheat. The temperature limited heater maybe formed with S curves (or other non-linear shapes) that accommodatedeformation of the temperature limited heater without causing failure ofthe heater.

[2782] In some embodiments, temperature limited heaters may be moreeconomical to manufacture or make than standard heaters. Typicalferromagnetic materials include iron or carbon steel, which areinexpensive compared to nickel-based heating alloys typically used ininsulated conductor heaters such as nichrome, Kanthal, etc. In oneembodiment of a temperature limited heater, the heater may bemanufactured in continuous lengths as an insulated conductor heater,thereby lowering costs and improving reliability.

[2783] Temperature limited heaters may be used for heating hydrocarbonformations such as, but not limited to, oil shale formations, coalformations, tar sands formations, etc. Temperature limited heaters mayalso be used in the field of environmental remediation to vaporize ordestroy soil contaminants. Embodiments of temperature limited heatersmay be used to heat a well bore or sub-sea pipeline to prevent paraffindeposition. In some embodiments, temperature limited heaters may be usedto heat a near wellbore region to reduce near wellbore oil viscosityduring production of high viscosity crude oils.

[2784] Certain embodiments of temperature limited heaters may be used inchemical or refinery processes at elevated temperatures that requirecontrol in a narrow temperature range to inhibit additional chemicalreactions or damage from locally elevated temperatures. Temperaturelimited heaters may also be used in pollution control devices (e.g.catalytic converters, oxidizers, etc.) to allow rapid heating to acontrol temperature without complex temperature control circuitry.Additionally, temperature limited heaters may be used in food processingto avoid damaging food with excessive temperatures. Temperature limitedheaters may also be used in the heat treatment of metals (e.g.,annealing of weld joints).

[2785] The Curie temperature of a conductor may be varied by choice offerromagnetic alloy. Curie temperature data for various metals is listedin “American Institute of Physics Handbook,” Second Edition,McGraw-Hill, pages 5-170 through 5-176. A ferromagnetic conductor mayinclude one or more of the ferromagnetic elements (iron, cobalt, andnickel) and/or alloys of these elements. Iron has a Curie temperature of770° C.; cobalt has a Curie temperature of 1131° C.; and nickel has aCurie temperature of 358° C. Alloying iron with smaller amounts ofcobalt raises the Curie temperature. For example, an iron alloy with 2%cobalt raises the Curie temperature from 770° C. to 800° C.; a cobaltcontent of 12% raises the Curie temperature to 900° C.; and a cobaltcontent of 20% raises the Curie temperature to 950° C. Conversely,alloying iron with smaller amounts of nickel lowers the Curietemperature. For example, an iron alloy with 20% nickel lowers the Curietemperature to 720° C., and a nickel content of 60% lowers the Curietemperature to 560° C. Other non-ferromagnetic elements (e.g., carbon,aluminum, silicon, and/or chromium) may also be alloyed with iron orother ferromagnetic materials to lower the Curie temperature. Some othernon-ferromagnetic elements such as vanadium may raise the Curietemperature. For example, an iron alloy with 5.9% vanadium has a Curietemperature of 815° C. In some embodiments, the Curie temperaturematerial may be a ferrite such as NiFe₂O₄. In other embodiments, theCurie temperature material may be a binary compound such as FeNi₃ orFe₃Al.

[2786] There is generally some decay in magnetic properties as the Curietemperature is approached. The “Handbook of Electrical Heating forIndustry” by C. James Erickson (IEEE Press, 1995) shows a typical curvefor 1% carbon steel (i.e., steel with 1% by weight carbon). The loss ofmagnetic permeability starts at temperatures above about 650° C. andtends to be complete when temperatures exceed about 730° C. Thus, thetemperature of self-regulation may be somewhat below an actual Curietemperature of a ferromagnetic conductor. The skin depth for currentflow in 1% carbon steel is about 0.132 cm at room temperature andincreases to about 0.445 cm at about 720° C. The skin depth sharplyincreases to over 2.5 cm from 720° C. to 730° C. Thus, a temperaturelimited heater embodiment using 1% carbon steel may self-regulatebetween about 650° C. and about 730° C.

[2787] Skin depth generally defines an effective penetration depth ofalternating current into a conductive material. In general, currentdensity decreases exponentially with distance from an outer surface to acenter along a radius of a conductor. The depth at which the currentdensity is approximately 37% of the surface current density is calledthe skin depth. For a solid cylindrical work piece with a diameter muchgreater than the penetration depth, or for hollow cylinders with a wallthickness exceeding the penetration depth, the skin depth dw is:

δ=1981.5*((ρ/(μ*f))^(1/2);  (118)

[2788] in which:

[2789] δ=skin depth in inches;

[2790] ρ=resistivity at operating temperature (ohm-cm);

[2791] μ=relative permeability; and

[2792] f=frequency (Hz).

[2793] EQN. 118 is obtained from the “Handbook of Electrical Heating forIndustry” by C. James Erickson (IEEE Press, 1995). For most metals theresistivity (ρ) increases with temperature.

[2794] FIGS. 477-481 depict estimated properties of Curie temperatureheaters based on analytical equations. FIG. 477 shows DC resistivityversus temperature for a 1% carbon steel Curie temperature heater. Theresistivity increases with temperature from about 20 microohm-cm atabout 0° C. to about 120 microohm-cm at about 725° C.

[2795]FIG. 478 shows magnetic permeability versus temperature for a 1%carbon steel Curie temperature heater. The magnetic permeabilitydecreases rapidly at temperatures over about 650° C. and the metal isvirtually non-magnetic above about 750° C.

[2796]FIG. 479 shows skin depth versus temperature for a 1% carbon steelCurie temperature heater at 60 Hz. The skin depth increases from about0.13 cm at about 0° C. to about 0.445 cm at about 720° C. due to theincrease in DC resistivity. The sharp increase in skin depth above 720°C. (greater than 2.5 cm) may be due to a decrease in magneticpermeability near the Curie temperature.

[2797]FIG. 480 shows AC resistance for a 244 m long, 2.5 cm diametercarbon steel pipe, Schedule XXS, versus temperature at 60 Hz. ACresistance increases by about a factor of two from room temperature toabout 650° C. due to the competing changes in resistivity and skin depthwith temperature. Above about 720° C., the sharp decrease in ACresistance is due to a decrease in magnetic permeability near the Curietemperature.

[2798]FIG. 481 shows heater power for a 244 m long, 2.5 cm diametercarbon steel pipe, Schedule XXS, at 600 A (constant) and 60 Hz. Thepower increases by about a factor of two from room temperature to about650° C., but then decreases sharply above about 650° C. due to adecrease in magnetic permeability near the Curie temperature. Thisdecrease in power near the Curie temperature results in self-regulationof the heater such that elevated temperatures are not exceeded.

[2799] In some embodiments, AC frequency may be adjusted to change theskin depth of a ferromagnetic material. For example, in 1% carbon steelat room temperature, the skin depth is about 0.132 cm at 60 Hz; at 440Hz the skin depth is about 0.046 cm. Since the heater diameter istypically larger than twice the skin depth, increasing the frequency mayallow for a smaller heater diameter. When the heater is cold, the heatermay be operated at a lower frequency, and when the heater is hot, theheater may be operated at a higher frequency in order to keep the skindepth nearly constant until the Curie temperature is reached. Linefrequency heating is generally favorable, however, because there is lessneed for expensive components (e.g., expensive power supplies thatchange the frequency).

[2800] In an embodiment, a temperature limited heater may include aninner conductor inside an outer conductor. The inner and outerconductors may be separated by an insulation layer. In certainembodiments, the inner and outer conductors may be coupled at the bottomof the heater. Electrical current may flow into the heater through theinner conductor and return through the outer conductor. Conversely, insome embodiments, electrical current may flow into the heater throughthe outer conductor and return through the inner conductor. One or bothconductors may include ferromagnetic material.

[2801] An insulation layer may comprise an electrically insulating buthigh thermal conductivity ceramic such as magnesium oxide, aluminumoxide, silicon dioxide, beryllium oxide, boron nitride, etc. Theinsulating layer may be a compacted powder (e.g., compacted ceramicpowder) with compaction improving thermal conductivity and providingbetter insulation resistance. For lower temperature applications,polymer insulations such as fluoropolymers, polyimides, polyamides,polyethylenes, etc. may be used. The insulating layer may be chosen tobe infrared transparent to aid heat transfer from the inner conductor tothe outer conductor. In an embodiment, the insulating layer may betransparent quartz sand. The insulation layer may be air or anon-reactive gas such as helium, nitrogen, sulfur hexafluoride, etc. ifdeformation tolerance is not required. If the insulation layer is air ora non-reactive gas, there may be insulating spacers that maintain aspacing between the inner conductor and the outer conductor to inhibitelectrical contact between the inner conductor and the outer conductor.The insulating spacers may be made of, for example, high purity aluminumoxide or another thermally conducting, electrically insulating material.

[2802] The insulation layer may be flexible and/or substantiallydeformation tolerant. For example, if the insulation layer is a solid orcompacted material that substantially fills the space between the innerand outer conductors, the heater may be flexible and/or substantiallydeformation tolerant. Forces on the outer conductor can be transmittedthrough the insulation layer to the solid inner conductor, which mayresist crushing. Such a heater may be bent, dog-legged, and spiraledwithout causing the outer conductor and the inner conductor toelectrically short to each other. Deformation tolerance may be importantif a wellbore is likely to undergo substantial deformation duringheating of the formation.

[2803] In certain embodiments, the outer conductor may be chosen forcorrosion and/or creep resistance. In one embodiment, austentitic(non-ferromagnetic) stainless steels such as 304H, 347H, 316 H or 310Hstainless steels may be used in the outer conductor. The outer conductormay also include a clad conductor. A corrosion resistant alloy such as304H stainless steel, for example, may be clad for corrosion protectionover a ferromagnetic carbon steel tubular. If high temperature strengthis not required, the outer conductor may also be constructed from aferromagnetic metal with good corrosion resistance (e.g., one of theferritic stainless steels). In one embodiment, a ferritic alloy of 82.3%iron with 17.7% chromium (Curie temperature 678° C.) may be used withthe chromium providing good corrosion resistance. A graph of dependenceof Curie temperature on the amount of chromium alloyed with iron can befound in The Metals Handbook, vol. 8, page 291 (American Society ofMaterials (ASM)). However, some designs such as the iron/chromium alloymay require a separate support rod or tubular (e.g., 347H stainlesssteel) to which the heater is coupled for strength and/or creepresistance.

[2804] In an embodiment with an inner ferromagnetic conductor and anouter ferromagnetic conductor, the skin effect current path occurs onthe outside of the inner conductor and on the inside of the outerconductor. Thus, the outside of the outer conductor may be clad with acorrosion resistant alloy, such as stainless steel, without affectingthe skin effect current path on the inside of the outer conductor.

[2805] The thickness of a conductor should generally be greater than theskin depth at the self-regulating temperature so there is a substantialdecrease in AC resistance of the ferromagnetic material when the skindepth increases sharply near the Curie temperature. In certainembodiments, the thickness of the conductor may be about 1.5 times theskin depth near the Curie temperature, about 3 times the skin depth nearthe Curie temperature, or even about 10 or more times the skin depthnear the Curie temperature.

[2806] In one embodiment, a temperature limited heater may include acomposite conductor of a ferromagnetic tubular with a non-ferromagnetichigh electrical conductivity core. The non-ferromagnetic high electricalconductivity core may allow the conductor to be smaller in diameter. Forexample, the conductor may be a composite 1.14 cm diameter conductorwith a core of 0.25 cm diameter copper clad with a 0.445 cm thickness ofcarbon steel surrounding the core. Having a composite conductor mayallow the electrical resistance of the temperature limited heater todecrease more steeply near the Curie temperature. When the skin depthbegins to increase near the Curie temperature, the skin depth mayinclude the copper core so that the electrical resistance decreases moresteeply. The composite conductor may also allow the temperature limitedheater to be more conductive and/or operate at lower voltages. Thecomposite conductor may also allow a relatively flat resistivity versustemperature profile. In certain embodiments, the relative thickness ofeach material in a composite conductor may be selected to produce aselected resistivity versus temperature profile for a temperaturelimited heater. In an embodiment, the composite conductor may be aninner conductor surrounded with 0.127 cm thick magnesium powder as aninsulator. The outer conductor may be 304H stainless steel with a wallthickness of 0.127 cm. The outside diameter of the heater may be about1.65 cm.

[2807] A composite conductor (e.g., a composite inner conductor or acomposite outer conductor) may be manufactured by many differentmethods, such as roll forming, tight fit tubing (e.g., cooling the innermember and heating the outer member, then inserting the inner memberfollowed by a drawing operation and/or allowing the system), explosiveor electromagnetic cladding, arc overlay welding, plasma powder welding,billet coextrusion, electroplating, drawing, sputtering, plasmadeposition, coextrusion casting, molten cylinder casting (of inner corematerial inside the outer or vice versa), insertion followed by weldingor high temperature braising, SAG (shielded active gas welding),insertion of an inner pipe. followed by mechanical expansion of theinner pipe by hydroforming or use of a pig to expand and swage the innerpipe, etc. In some embodiments, the ferromagnetic conductor may also bebraided over the non-ferromagnetic conductor. In certain embodiments,composite conductors may be formed using methods similar to those usedfor cladding (e.g., cladding copper to steel).

[2808] In an embodiment, two or more conductors may be drawn together toform a composite conductor. In certain embodiments, a relatively softferromagnetic conductor (e.g., soft iron such as 1018 steel) may be usedto form a composite conductor. A relatively soft ferromagnetic conductortypically has a low carbon content. A relatively soft ferromagneticconductor may be useful in drawing processes for forming compositeconductors and/or other processes that require stretching or bending ofthe ferromagnetic conductor. In a drawing process, the ferromagneticconductor may be annealed after one or more steps of the drawingprocess. The ferromagnetic conductor may be annealed in an inert gasatmosphere to inhibit oxidation of the conductor. In some embodiments,an oil may be placed on the ferromagnetic conductor to inhibit oxidationof the conductor during processing.

[2809]FIG. 482 depicts one embodiment for forming a composite conductor.Ingot 3176 may be a ferromagnetic conductor (e.g., iron or carbonsteel). Ingot 3176 may be placed in chamber 3178. Chamber 3178 may madeof materials that are electrically insulating, non-reactive, and able towithstand temperatures up to about 800° C. In one embodiment, chamber3178 is a quartz chamber. In some embodiments, an inert, ornon-reactive, gas (e.g., argon, nitrogen, etc.) may be placed in chamber3178. In certain embodiments, a flow of inert gas may be provided tochamber 3178 to maintain a pressure in the chamber. Induction coil 3180may be placed around chamber 3178. An alternating current may besupplied to induction coil 3180 to inductively heat ingot 3176. Havingthe inert gas inside chamber 3178 may inhibit oxidation or corrosion ofingot 3176.

[2810] Inner conductor 3182 may be placed inside ingot 3176. Innerconductor 3182 may be a non-ferromagnetic conductor (e.g., copper oraluminum) that melts at a lower temperature than ingot 3176. In anembodiment, ingot 3176 may be heated to a temperature above the meltingpoint of inner conductor 3182 and below the melting point of the ingot.Inner conductor 3182 may then melt and substantially fill the spaceinside ingot 3176 (i.e., the inner annulus of the ingot). A cap may beplaced at the bottom of ingot 3176 to inhibit inner conductor 3182 fromflowing or leaking out of the inner annulus of the ingot. After innerconductor 3182 has sufficiently melted to substantially fill the innerannulus of ingot 3176, the inner conductor and the ingot may be allowedto cool back to room temperature. The cooling of ingot 3176 and innerconductor 3182 may be maintained at a relatively slow rate to allowinner conductor 3182 to form a good soldering bond with ingot 3176. Therate of cooling may depend on, for example, the types of materials usedfor the ingot and the inner conductor.

[2811] In some embodiments, a tube-in-tube milling process from dualmetal strips, such as that available from Precision Tube Technology(Houston, Tex.), may be employed to form a composite conductor. Thetube-in-tube milling process may also be used to form cladding onconductors (e.g., copper cladding inside carbon steel) or form any twomaterials into a tight fit tube within a tube configuration.

[2812]FIG. 483 depicts an embodiment of an inner conductor and an outerconductor formed by a tube-in-tube milling process. Outer conductor 3184is coupled to inner conductor 3186. Outer conductor 3184 may be weldablematerial such as steel. Inner conductor 3186 may have a higherelectrical conductivity than outer conductor 3184. In an embodiment,inner conductor 3186 is copper or aluminum. Weld bead 3188 may be formedby on outer conductor 3184.

[2813] In a tube-in-tube milling process, flat strips of material forthe outer conductor have a thickness substantially equal to the desiredwall thickness of the outer conductor. The width of the strips may allowfor formation of a tube of a desired inner diameter. The flat strips arewelded end-to-end so that a desired length of outer conductor can beformed. Flat strips of material for an inner conductor may be cut tosize so that strips will have a diameter that fits inside the outerconductor. The flat strips of material may be welded together end-to-endto achieve a length that is substantially the same as the length of thewelded together flat strips of outer conductor material. The flat stripsfor the outer conductor and the flat strips for the inner conductor maybe fed to into separate accumulators. Both accumulators may be coupledto a tube mill. The two flat strips may be sandwiched together at thebeginning of the tube mill.

[2814] The tube mill may form the flat strips into a tube-in-tube shape.After the tube-in-tube shape has been formed, a non-contact highfrequency induction welder may heat the ends of the strips of the outerconductor to a forging temperature of the outer conductor. The ends ofthe strips then may be brought together to forge weld the ends of theouter conductor into a weld bead. Excess weld bead material may be cutoff. In some embodiments, the tube-in-tube produced by the tube mill maybe further processed (e.g., annealed, pressed, etc.) to place thetube-in-tube into proper size and/or shape. The result of thetube-in-tube process may be an inner conductor placed inside an outerconductor as shown in FIG. 483.

[2815]FIG. 484 depicts an embodiment of a Curie temperature heater witha ferromagnetic inner conductor. Inner conductor 3190 may be a carbonsteel pipe, Schedule XXS, with a diameter of about 2.5 cm. In someembodiments, inner conductor 3190 may be iron or another ferromagneticmaterial. Electrical insulator 3192 may be magnesium powder. Outerconductor 3194 may be copper or any other non-ferromagnetic material(e.g., aluminum). Outer conductor 3194 may be coupled to jacket 3196.Jacket 3196 may be 304 stainless steel. When used as a heater, themajority of power in this embodiment may be dissipated in innerconductor 3190.

[2816]FIG. 485 depicts an embodiment of a Curie temperature heater witha ferromagnetic inner conductor and a non-ferromagnetic core. Innerconductor 3190 may be carbon steel or iron. Core 3198 may be tightlybonded inside inner conductor 3190. Core 3198 may be a copper rod oranother rod of non-ferromagnetic material (e.g., aluminum). Core 3198may be inserted as a tight fit inside inner conductor 3190 before adrawing operation. Electrical insulator 3192 may be magnesium powder.Outer conductor 3194 may be 304 stainless steel. A drawing operation tocompact electrical insulator 3192 may ensure good electrical contactbetween inner conductor 3190 and core 3198 in the inner conductor. Inthis embodiment, power may be dissipated during heating mainly in innerconductor 3190 until near the Curie temperature. Resistance may thendecrease sharply as alternating current penetrates core 3198.

[2817]FIGS. 486, 487, and 488 depict AC resistance versus temperaturefor various conductors as calculated using analytical equations setforth herein. Generally, the AC resistance of a conductor in a heater isindicative of the heat output (power) of the heater for a constantvoltage (power=(current)²×(resistance)). FIG. 486 depicts AC resistanceversus temperature for a 1.5 cm diameter iron conductor. Curve 3200shows that the AC resistance steadily increases with temperature (whichis typical for most metals) and begins to decrease as the temperaturenears the Curie temperature. The AC resistance decreases sharply abovethe Curie temperature (above about 740° C.).

[2818]FIG. 487 depicts AC resistance versus temperature for a 1.5 cmdiameter composite conductor of iron and copper. Curve 3202 depicts ACresistance versus temperature for a 0.25 cm diameter copper core insidean iron conductor with an outside diameter of 1.5 cm. Curve 3204 depictsAC resistance versus temperature for a 0.5 cm diameter copper coreinside an iron conductor with an outside diameter of 1.5 cm. Thealternating current at about room temperature travels through the skinof the iron conductor. As shown in FIG. 487, increasing the diameter ofthe copper core, which decreases the thickness of the iron conductor forthe same outside diameter, reduces the temperature at which the ACresistance begins to decrease. The alternating current may begin to flowthrough the larger copper core at lower temperatures because of thesmaller thickness of the iron conductor.

[2819]FIG. 488 depicts AC resistance versus temperature for a 1.3 cmdiameter composite conductor of iron and copper and AC resistance versustemperature for the 1.5 cm diameter composite conductor of iron andcopper (curve 3204) from FIG. 487. Curve 3206 depicts AC resistanceversus temperature for a 0.3 cm diameter copper core inside a 0.5 cmthick iron conductor. As shown in FIG. 488, the 1.3 cm diametercomposite conductor with a 0.3 cm (curve 3206) has a relatively flatresistance profile from about 200° C. to about 600° C. This relativelyflat resistance profile may provide a desired heat output profile foruse in heating a hydrocarbon containing formation, or any othersubsurface formation. A desired heater for heating a hydrocarboncontaining formation may increase the heat output to a relativelyconstant level at low temperature and then maintain the relativelyconstant heat output level over a large temperature range. Such a heatermay more quickly and more uniformly heat a hydrocarbon containingformation.

[2820] A heater with the resistance profile of curve 3204 (i.e., theresistance slowly decreases with temperature above a certaintemperature) may be used in certain embodiments for heating subsurfaceformations. For example, a heater may be needed to provide more poweroutput at lower temperatures to heat a formation with significantamounts of water. A heater, which provides more power output at lowertemperatures, may be useful in removing the water without providingexcess heat to other portions of the formation that do not containsignificant amounts of water.

[2821]FIG. 489 depicts an embodiment of a Curie temperature heater witha ferromagnetic outer conductor. Inner conductor 3190 may be copper.Electrical insulator 3192 may be magnesium powder. Outer conductor 3194may be carbon steel pipe, Schedule XXS, with a diameter of about 2.5 cm.In this embodiment, the power may be dissipated mainly in outerconductor 3194, resulting in a small temperature differential acrosselectrical insulator 3192.

[2822]FIG. 490 depicts an embodiment of a Curie temperature heater witha ferromagnetic outer conductor that is clad with a corrosion resistantalloy. Inner conductor 3190 may be copper. Electrical insulator 3192 maybe magnesium powder. Outer conductor 3194 may be a carbon steel pipe,Schedule XXS, with a diameter of about 2.5 cm. Outer conductor 3194 maybe coupled to jacket 3196. Jacket 3196 may be 304 stainless steel. Inthis embodiment, the power may be dissipated mainly in outer conductor3194, resulting in a small temperature differential across electricalinsulator 3192. Jacket 3196 may provide corrosion resistance againstcorrosive fluids in the borehole (e.g., sulfidizing and carburizinggases).

[2823]FIG. 491 depicts an embodiment of a Curie temperature heater witha ferromagnetic outer conductor that is clad with a conductive layer anda corrosion resistant alloy. Inner conductor 3190 may be copper.Electrical insulator 3192 may be magnesium powder. Outer conductor 3194may be a carbon steel pipe, Schedule XXS, with a diameter of about 2.5cm. Outer conductor 3194 may be coupled to jacket 3196. Jacket 3196 maybe 304 stainless steel. In an embodiment, conductive layer 3208 may beplaced between outer conductor 3194 and jacket 3196. Conductive layer3208 may be a copper layer. In this embodiment, the power may bedissipated mainly in outer conductor 3194, resulting in a smalltemperature differential across electrical insulator 3192. Conductivelayer 3208 may provide for a sharper decrease in the resistance of outerconductor 3194 as the outer conductor approaches the Curie temperature.Jacket 3196 may provide corrosion resistance against corrosive fluids inthe borehole (e.g., sulfidizing and carburizing gases).

[2824] In some embodiments, an inner conductor may include two or moredifferent materials. For example, the composite inner conductor mayinclude iron clad over nickel clad over a copper core. Two or morematerials may be used to obtain a flatter electrical resistivity versustemperature profile in a temperature region below the Curie temperature.

[2825] In one heater embodiment, an inner conductor may be a 1.9 cmdiameter iron rod, an insulating layer may be 0.25 cm thick magnesiumpowder, and an outer conductor may be 0.635 cm thick 347H stainlesssteel. The heater may be energized at line frequency (e.g., 60 Hz) froma substantially constant current source. Stainless steel may be chosenfor its corrosion resistance in the gaseous subsurface environmentand/or for superior creep resistance at elevated temperatures. Below theCurie temperature, a majority of the heat may be dissipated in the ironinner conductor. With a heat injection rate of about 820 watts/meter,the temperature differential across the insulating layer will beapproximately 40° C., so that the temperature of the outer conductorwill be about 40° C. cooler than the temperature of the innerferromagnetic conductor.

[2826] In another heater embodiment, an inner conductor may be a 1.9 cmdiameter rod of copper or copper alloy such as LOHM (about 94% copper,6% nickel by weight), an insulating layer may be transparent quartzsand, and an outer conductor may be 0.635 cm thick 1% carbon steel cladwith 0.25 cm thick 310 stainless steel. The carbon steel in the outerconductor may be clad with copper between the carbon steel and thestainless steel jacket to reduce a thickness of the carbon steel neededto get substantial resistance changes near the Curie temperature. Anadvantage of a ferromagnetic outer conductor is that the heat dissipatesprimarily on the outer conductor, resulting in a small temperaturedifferential across the insulating layer. A lower thermal conductivitymaterial may therefore be chosen for the insulation because the mainheat dissipation occurs in the outer conductor. Copper or copper alloymay be chosen for the inner conductor to reduce the heat dissipation inthe inner conductor. Other metals, however, may also be used for theinner conductor (e.g., aluminum and aluminum alloys, phosphor bronze,beryllium copper, brass, etc.). These metals may be chosen for their lowelectrical resistivity and magnetic permeabilities near 1 (i.e.,substantially non-ferromagnetic).

[2827] In another embodiment, a Curie temperature heater may be aconductor-in-conduit heater. Ceramic insulators may be positioned on theinner conductor. The inner conductor may make sliding electrical contactwith the outer conduit in a sliding contactor section located at or nearthe bottom of the heater.

[2828]FIG. 492 depicts an embodiment of a conductor-in-conduittemperature limited heater. Conductor 1112 may be coupled (e.g.,cladded, press fit, drawn inside, etc.) to ferromagnetic conductor 3212.Ferromagnetic conductor 3212 may be coupled to the outside of conductor1112 so that alternating current propagates through the skin depth ofthe ferromagnetic conductor at room temperature. Conductor 1112 mayprovide mechanical support for ferromagnetic conductor 3212 at elevatedtemperatures. Ferromagnetic conductor 3212 may be iron, an iron alloy(e.g., iron with about 18% by weight chromium for corrosion resistance(445 steel)), or any other ferromagnetic material. In one embodiment,conductor 1112 is 304 stainless steel and ferromagnetic conductor 3212is 445 steel. Conductor 1112 and ferromagnetic conductor 3212 may beelectrically coupled to conduit 1176 with sliding connector 1202.Conduit 1176 may be a non-ferromagnetic material such as stainlesssteel.

[2829]FIG. 493 depicts another embodiment of a conductor-in-conduittemperature limited heater. Conduit 1176 may be coupled (e.g., cladded,press fit, drawn inside, etc.) to ferromagnetic conductor 3212.Ferromagnetic conductor 3212 may be coupled to the inside of conduit1176 so that alternating current propagates through the skin depth ofthe ferromagnetic conductor at room temperature. Conduit 1176 mayprovide mechanical support for ferromagnetic conductor 3212 at elevatedtemperatures. Conduit 1176 and ferromagnetic conductor 3212 may beelectrically coupled to conductor 1112 with sliding connector 1202.

[2830]FIG. 494 depicts an embodiment of a conductor-in-conduittemperature limited heater with an insulated conductor as the conductor.Insulated conductor 1124 may include core 3198, electrical insulator3192 and jacket 3196. Jacket 3196 may be stainless steel for corrosionresistance. Endcap 3218 may be placed at an end of insulated conductor1124 to couple core 3198 to sliding connector 1202. Endcap 3218 may bemade of non-corrosive, electrically conducting materials such as nickelor stainless steel. Endcap 3218 may be coupled to the end of insulatedconductor 1124 by any suitable method (e.g., welding, soldering,braising, etc.). Sliding connector 1202 may electrically couple core3198 and endcap 3218 to ferromagnetic conductor 3212. Conduit 1176 mayprovide support for ferromagnetic conductor 3212 at elevatedtemperatures.

[2831]FIG. 495 depicts an embodiment of an insulatedconductor-in-conduit temperature limited heater. Insulated conductor1124 may include core 3198, electrical insulator 3192 and jacket 3196.Insulated conductor 1124 may be coupled to ferromagnetic conductor 3212with connector 3220. Connector 3220 may be made of non-corrosive,electrically conducting materials such as nickel or stainless steel.Connector 3220 may be coupled using suitable methods for electricallycoupling (e.g. welding, soldering, braising, etc.). Insulated conductor1124 may be placed along a wall of ferromagnetic conductor 3212.Insulated conductor 1124 may provide mechanical support forferromagnetic conductor 3212 at elevated temperatures. In someembodiments, other structures (e.g., a conduit) may be used to providemechanical support for ferromagnetic conductor 3212.

[2832]FIG. 496 depicts an embodiment of an insulatedconductor-in-conduit temperature limited heater. Insulated conductor1124 may be coupled to endcap 3218. Endcap 3218 may be coupled tocoupling 3222. Coupling 3222 may electrically couple insulated conductor1124 to ferromagnetic conductor 3212. Coupling 3222 may be a flexiblecoupling. For example, coupling 3222 may be braided wire or includeflexible materials. Coupling 3222 may be made of non-corrosive materialssuch as nickel, stainless steel, and/or copper.

[2833] In another embodiment, a Curie temperature heater may include asubstantially U-shaped heater with a ferromagnetic cladding over anon-ferromagnetic core (in this context, the “U” may have a curved or,alternatively, orthogonal shape). A U-shaped, or hairpinned, heater mayhave insulating support mechanisms (e.g., polymer or ceramic spacers)that inhibit the two legs of the hairpin from electrically shorting toeach other. In some embodiments, a hairpin heater may be installed in acasing (e.g., an environmental protection casing). The insulators mayinhibit electrical shorting to the casing and may facilitateinstallation of the heater in the casing. The cross section of thehairpin heater may be, but is not limited to, circular, square, orrectangular.

[2834]FIG. 497 depicts an embodiment of a Curie temperature heater witha hairpin inner conductor. Inner conductor 3190 may be placed in ahairpin configuration with two legs coupled by a substantially U-shapedsection at or near the bottom of the heater. Current may enter innerconductor 3190 through one leg and exit through the other leg. Innerconductor 3190 may be carbon steel or iron. Core 3198 may be placedinside inner conductor 3190. In certain embodiments, inner conductor3190 may be cladded to core 3198. Core 3198 may be a copper rod. Thelegs of the heater may be insulated from each other and from casing 3224by spacers 3226. Spacers 3226 may be alumina spacers. Spacers 3226 maybe about 90% to about 99.8% alumina. Weld beads or other protrusions maybe placed on inner conductor 3190 to maintain a location of spacers 3226on the inner conductor. In some embodiments, spacers 3226 may includetwo sections that are fastened together around inner conductor 3190.Casing 3224 may be an environmentally protective casing made of, forexample, stainless steel.

[2835] In certain embodiments, a Curie temperature heater mayincorporate curves, bends or waves in a relatively straight heater toallow thermal expansion and contraction of the heater withoutoverstressing materials in the heater. When a cool heater is heated or ahot heater is cooled, the heater expands or contracts in proportion tothe change in temperature and the coefficient of thermal expansion ofmaterials in the heater. For long straight heaters that undergo widevariations in temperature during use and are fixed at more than onepoint (e.g., due to mechanical deformation of the wellbore), theexpansion or contraction may cause the heater to bend, kink, and/or pullapart. Use of an “S” bend, or other curves, bends or waves, in theheater at intervals in the heated length may provide a spring effect andallow the heater to expand or contract more gently so that the heaterdoes not bend, kink, or pull apart.

[2836] A 310 stainless steel heater subjected to about 500° C.temperature change may shrink/grow approximately 0.85% of the length ofthe heater with this temperature change. Thus, a length of about 3 m ofa heater would contract about 2.6 cm when it cools through 500° C. Ifthis heater were affixed at about 3 m intervals, such a change in lengthcould stretch and, possibly, break the heater. FIG. 498 depicts anembodiment of an “S” bend in a heater. The additional material in the“S” bend may allow for thermal contraction or expansion of heater 3227without damage to the heater.

[2837] In some embodiments, a temperature limited heater may include asandwich construction with both current supply and current return pathsseparated by an insulator. The sandwich heater may include two outerlayers of conductor, two inner layers of ferromagnetic material, and alayer of insulator between the ferromagnetic layers. The cross-sectionaldimensions of the heater may be optimized for mechanical flexibility andspoolability. The sandwich heater may be formed as a bimetallic stripthat is bent back upon itself. The sandwich heater may be inserted in acasing, such as an environmental protection casing, and may be separatedfrom the casing with an electrical insulator.

[2838] A heater may include a section that passes through an overburden.In some embodiments the portion of the heater in the overburden may notneed to have as a power dissipation as a portion of the heater adjacentto hydrocarbon layers that are to be subjected to in situ conversion.The section of the heater positioned in the overburden may be designedto have limited heat dissipation. In some embodiments, the overburdensection of the heater may include a copper or copper alloy innerconductor. The overburden section may also include a copper outerconductor clad with a corrosion resistant alloy.

[2839] A temperature limited heater may be constructed in sections(e.g., about 10 m long) that are coupled (e.g., welded) together to formthe entire heater. A splice section may be formed between the sections,for example, by welding the inner conductors, filling the splice sectionwith an insulator, and then welding the outer conductor. Alternatively,the heater may be formed from larger diameter tubulars and drawn down toa final length and diameter. If the insulation layer is magnesiumpowder, the insulation layer may be added by weld-fill-draw (startingfrom metal strip) or fill-draw (starting from tubulars) methods wellknown in the industry in the manufacture of mineral insulated heatercables. The assembly and filling can be done in either a vertical orhorizontal orientation. The final heater assembly may be spooled onto alarge diameter spool (e.g., about 6 m in diameter) and transported to asite of a formation for subsurface deployment. Alternatively, the heatermay be assembled on site in sections as the heater is lowered verticallyinto a wellbore.

[2840] A Curie temperature heater may be a single-phase heater or athree-phase heater. In a three-phase heater embodiment, a heater may bea three-phase heater in either a delta or Wye configuration. Each of thethree ferromagnetic conductors may be inside a separate sheath. Aconnection between conductors may be made at the bottom of the heaterinside a splice section. The three conductors may remain insulated fromthe sheath inside the splice section.

[2841]FIG. 499 depicts an embodiment of a three-phase Curie temperatureheater with ferromagnetic inner conductors. Each leg 3228 may have innerconductor 3190, core 3198, and jacket 3196. Inner conductors 3190 may beiron 1% carbon steel. Inner conductors 3190 may have core 3198. Core3198 may be copper. Each inner conductor 3190 may be coupled to its ownjacket 3196. Jacket 3196 may be a 304H stainless steel sheath forcorrosion resistance. Electrical insulator 3192 may be placed betweeninner conductor 3190 and jacket 3196. Inner conductor 3190 may be ironcarbon steel with an outside diameter of about 1.14 cm and a thicknessof about 0.445 cm. Core 3198 may be a copper core with a 0.25 cmdiameter. Each leg 3228 of the heater may be coupled to terminal block3230. Terminal block 3230 may be filled with insulation material 3232and have an outer surface of stainless steel. Insulation material 3232may, in some embodiments, be magnesium oxide or other suitableelectrically insulating material. Inner conductors 3190 of legs 3228 maybe coupled (e.g., welded) in terminal block 3230. Jackets 3196 of legs3228 may be coupled (e.g., welded) to an outer surface of terminal block3230. Terminal block 3230 may include two halves coupled together aroundthe coupled portions of legs 3228.

[2842] The heated section of the heater may be about 245 m long. Thethree-phase heater may be Wye connected and operated at about 150 A. Theresistance of one leg of the heater may increase from about 1.1 ohms atroom temperature to about 3.1 ohms at about 650° C. The resistance ofone leg may decrease rapidly above about 720° C. to about 1.5 ohms. Thevoltage may increase from about 165 V at room temperature to about 465 Vat 650° C. The voltage may decrease rapidly above about 720° C. to about225 V. The power dissipation per leg may increase from about 102watts/meter at room temperature to about 285 watts/meter at 650° C. Thepower dissipation per leg may decrease rapidly above about 720° C. toabout 1.4 watts/meter. Other embodiments of inner conductor 3190, core3198, jacket 3196, and/or electrical insulator 3192 may be used in thethree-phase Curie temperature heater shown in FIG. 499. Any embodimentof a single-phase Curie temperature heater may be used as a leg of athree-phase Curie temperature heater.

[2843] In some three-phase heater embodiments, three ferromagneticconductors may be separated by an insulation layer inside a common outermetal sheath. The three conductors may be insulated from the sheath orthe three conductors may be connected to the sheath at the bottom of theheater assembly. In another embodiment, the single outer sheath or threeouter sheaths may be ferromagnetic conductors and the inner conductorsmay be non-ferromagnetic (e.g., aluminum, copper or an alloy thereof).Alternatively, each of the three non-ferromagnetic conductors may beinside a separate ferromagnetic sheath, and a connection between theconductors may be made at the bottom of the heater inside a splicesection. The three conductors may remain insulated from the sheathinside the splice section.

[2844]FIG. 500 depicts another embodiment of a three-phase Curietemperature heater with ferromagnetic inner conductors in a commonjacket. Inner conductors 3190 may be placed in electrical insulation3192. Inner conductors 3190 and electrical insulation 3192 may be placedin a single jacket 3196. Jacket 3196 may be a stainless steel sheath forcorrosion resistance. Jacket 3196 may have an outside diameter ofbetween about 2.5 cm and about 5 cm (e.g., about 3.1 cm (1.25 inches) orabout 3.8 cm (1.5 inches)). Inner conductors 3190 may be coupled at ornear the bottom of the heater at termination 3234. Termination 3234 maybe a welded termination of inner conductors 3190. Inner conductors 3190may be coupled in a Wye configuration.

[2845] In some embodiments, a Curie temperature heater may include asingle ferromagnetic conductor with current returning through theformation. The heating element may be a ferromagnetic tubular (e.g., 446stainless steel (with 25% chromium and a Curie temperature above about620° C.) clad over 304H stainless steel) that extends through the heatedtarget section and makes electrical contact to the formation in anelectrical contacting section. The electrical contacting section may belocated below a heated target section (e.g., in an underburden of theformation). In an embodiment, the electrical contacting section may be asection about 60 m deep with a larger diameter wellbore. The tubular inthe electrical contacting section may be a high electrical conductivitymetal. The annulus in the electrical contacting section may be filledwith a contact material/solution such as salty brine or other materialsthat enhance electrical contact with the formation (e.g., metal beads,hematite, etc.). The electrical contacting section may be located in abrine saturated zone to maintain electrical contact through the brine.In this electrical contacting section, the tubular diameter may also beincreased to allow maximum current flow into the formation with thelowest heat dissipation. Current flows through the ferromagnetic tubularin the heated section and heats the tubular.

[2846]FIG. 501 depicts an embodiment of a Curie temperature heater withcurrent return through the formation. Heating element 3236 may be placedin opening 544 in hydrocarbon layer 522. Heating element 3236 may be a446 stainless steel clad over 304H stainless steel tubular that extendsthrough hydrocarbon layer 522. Heating element 3236 may be coupled tocontacting element 3238. Contacting element 3238 may have a higherelectrical conductivity than heating element 3236. Contacting element3238 may be placed in electrical contacting section 3240, which islocated below hydrocarbon layer 522. Contacting element 3238 may makeelectrical contact with the earth in electrical contacting section 3240.Contacting element 3238 may be placed in contacting wellbore 3242.Contacting element 3238 may have a diameter between about 10 cm andabout 20 cm (e.g., about 15 cm). The diameter of contacting element 3238may be sized to increase contact area between contacting element 3238and contact solution 3244. The diameter of contacting element 3238 maybe increased to a size to increase the contact area without excessivelyincreasing the costs of installing and using contacting element 3238,contacting wellbore 3242, and/or contact solution 3244 as well asmaintaining sufficient electrical contact between contacting element3238 and electrical contacting section 3240. Increasing the contact areamay inhibit evaporation or boiling off of contact solution 3244.

[2847] Contacting wellbore 3242 may be, for example, a section about 60m deep with a larger diameter wellbore than opening 544. The annulus ofcontacting wellbore 3242 may be filled with contact solution 3244.Contact solution 3244 may be salty brine or other material that enhanceselectrical contact with electrical contacting section 3240. In someembodiments, electrical contacting section 3240 is a water-saturatedzone that maintains electrical contact through the brine. Contactingwellbore 3242 may be under-reamed to a larger diameter (e.g., a diameterbetween about 25 cm and about 50 cm) to allow maximum current flow intoelectrical contacting section 3240 with low heat dissipation. Currentmay flow through heating element 3236, boiling moisture from thewellbore, and heating until the element self-regulates at the Curietemperature.

[2848] In an embodiment, three-phase Curie temperature heaters may bemade with current connection through the earth formation. Each heatermay include of a single Curie temperature heating element, with anelectrical contacting section in a brine saturated zone below a heatedtarget section. In an embodiment, three such heaters may be connectedelectrically at the surface in a three-phase Wye configuration. Theheaters may be deployed in a triangular pattern from the surface. Incertain embodiments, the current returns through the earth to a neutralpoint between the three heaters. The three-phase Curie heaters may bereplicated in a pattern that covers the entire formation.

[2849]FIG. 502 depicts an embodiment of a three-phase Curie temperatureheater with current connection through the earth formation. Three legs3246, 3248, and 3250 may be placed in a formation. Each leg 3246, 3248,and 3250 may have heating element 3236 placed in each opening 544 inhydrocarbon layer 522. Each leg may also have contacting element 3238placed in contact solution 3244 in contacting wellbore 3242. Eachcontacting element 3238 may be electrically coupled to electricalcontacting section 3240 through contact solution 3244. Legs 3246, 3248,and 3250 may be connected in a Wye configuration that results in aneutral point in electrical contacting section 3240 between the threelegs. FIG. 503 depicts a plan view of the embodiment of FIG. 502 withneutral point 3252 shown positioned centrally between legs 3246, 3248,and 3250.

[2850] In addition to the micro-scale Curie temperature self-regulationcharacteristics, an embodiment of a temperature limited heater may alsobe tailored to achieve power control on a more global scale. Powercontrol on a more global scale may enable more of the heated length toself-regulate near the Curie temperature and thereby achieve more totalheat infectivity. For example, a long section of heater through a highthermal conductivity zone may be tailored to deliver more heatinjectivity through that zone. Tailoring of the heater can be achievedby changing cross-sectional areas of the heating elements (e.g., bychanging the ratios of copper to iron), as well as using differentmetals in the heating elements. Thermal conductance of the insulationlayer may also be modified in certain sections to control the thermaloutput to raise or lower the apparent Curie temperature self-regulationzone.

[2851] Simulations have been performed to compare the use of Curietemperature heaters and non-Curie temperature heaters in an oil shaleformation. Simulation data was produced for conductor-in-conduit heatersplaced in 16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet)spacing between heaters using one or more of the analytical equationsset forth herein, a formation simulator (e.g., STARS), and a nearwellbore simulator (e.g., ABAQUS). Standard conductor-in-conduit heatersincluded stainless steel conductors and conduits. Temperature limitedconductor-in-conduit heaters included 1% carbon steel conductors andconduits. Results from the simulations are depicted in FIGS. 504-506.

[2852]FIG. 504 depicts heater temperature at the conductor of aconductor-in-conduit heater versus depth of the heater in the formationfor a simulation after 20,000 hours of operation. Heater power was setat about 820 watts/meter. Curve 3254 depicts the conductor temperaturefor standard conductor-in-conduit heaters. Curve 3254 shows that a largevariance in conductor temperature and a significant number of hot spotsdeveloped along the length of the conductor. The temperature of theconductor had a minimum value of about 490° C. Curve 3256 depictsconductor temperature for temperature limited conductor-in-conduitheaters. As shown in FIG. 504, temperature distribution along the lengthof the conductor was more controlled for the temperature limitedheaters. In addition, the operating temperature of the conductor wasabout 730° C. for the temperature limited heaters. Thus, more heat inputwould be provided to the formation for a similar heater power usingtemperature limited heaters.

[2853]FIG. 505 depicts heater heat flux versus time for the heaters usedin the simulation for heating oil shale. Curve 3258 depicts heat fluxfor standard conductor-in-conduit heaters. Curve 3260 depicts heat fluxfor temperature limited conductor-in-conduit heaters. As shown in FIG.505, heat flux for the temperature limited heaters is maintained at ahigher value for a longer period of time than heat flux for standardheaters. The higher heat flux may provide more uniform and fasterheating of the formation.

[2854]FIG. 506 depicts accumulated heat input versus time for theheaters used in the simulation for heating oil shale. Curve 3262 depictsaccumulated heat input for standard conductor-in-conduit heaters. Curve3264 depicts accumulated heat input for temperature limitedconductor-in-conduit heaters. As shown in FIG. 506, accumulated heatinput for the temperature limited heaters increases faster thanaccumulated heat input for standard heaters. The faster accumulation ofheat in the formation using temperature limited heaters may decrease thetime needed for retorting the formation. Retorting for an oil shaleformation typically begins around an accumulated heat input of 1.1×10⁸KJ/meter. This value of accumulated heat input is reached around about 5years for temperature limited heaters and between 9 and 10 years forstandard heaters.

[2855] Analytical solutions for the AC conductance of ferromagneticmaterials may be useful to predict the behavior of ferromagneticmaterial and/or other materials during heating of a formation. In oneembodiment, the AC conductance of a wire of uniform circular crosssection made of ferromagnetic materials may be solved for analytically.For a wire of radius b, the magnetic permeability, electricpermittivity, and electrical conductivity of the wire may be denoted byμ, ε, and σ, respectively.

[2856] Maxwell's Equations are:

∇· B=0;  (119)

∇× E+∂B/∂t=0;  (120)

∇· D=ρ;  (121)

and ∇× H−∂D/∂t=J.  (122)

[2857] The constitutive equations for the wire are:

D=εE,B=μH,J=σE.  (123)

[2858] Substituting EQN. 123 into EQNS. 119-122, setting ρ=0, andwriting:

E (r,t)= E _(S)( r )e ^(jωt)  (124)

and H (r,t)= H _(S)( r )e ^(jωt),  (125)

[2859] the following equations are obtained:

∇·H _(S)=0;  (126)

∇×E _(S) +jμωH _(S)=0;  (127)

∇·E _(S)=0;  (128)

and ∇×H _(S) −jωεE _(S) =σE _(S).  (129)

[2860] Note that EQN. 128 follows on taking the divergence of EQN. 129.Taking the curl of EQN. 127, using the fact that for any vector functionF:

∇×∇×F=∇ (∇. F )−∇² F,  (130)

[2861] and applying EQN. 126, it is deduced that:

∇² E _(S) −C ² E _(S)=0,  (131)

where C ² =jωμσ _(eff),  (132)

with σ_(eff) =σ+jωε.  (133)

[2862] For a cylindrical wire, it is assumed that:

E _(S) =E _(S)(r){circumflex over (k)},  (134)

[2863] which means that E_(S)(r) satisfies the equation: $\begin{matrix}{{{\frac{1}{r}\frac{\partial\quad}{\partial r}\left( {r\frac{\partial E_{S}}{\partial r}} \right)} - {C^{2}E_{S}}} = 0.} & (135)\end{matrix}$

[2864] The general solution of EQN. 135 is:

E _(S)(r)=AI ₀(Cr)+BK ₀(Cr).  (136)

[2865] B must vanish as K₀ is singular at r=0, and so it is deducedthat: $\begin{matrix}{{E_{S}(r)} = {{{E_{S}(b)}\frac{I_{0}({Cr})}{I_{0}({Cb})}} = {{{E_{S}(r)}}{^{\quad {\varphi {(r)}}}.}}}} & (137)\end{matrix}$

[2866] The power dissipation in the wire per unit length (P) is givenby: $\begin{matrix}{{P = {\frac{1}{2}{\int_{0}^{b}\quad {{{r2}}\quad \pi \quad r\quad \sigma {E_{S}}^{2}}}}},} & (138)\end{matrix}$

[2867] and the mean current squared (<I²>) is given by: $\begin{matrix}{{\text{<}I^{2}\text{>}} = {{\frac{1}{2}{{\int_{0}^{b}\quad {{{r2}}\quad \pi \quad r\quad J_{S}}}}^{2}} = {\frac{1}{2}{{{\int_{0}^{b}\quad {{{r2}}\quad \pi \quad r\quad \sigma \quad E_{S}}}}^{2}.}}}} & (139)\end{matrix}$

[2868] EQNS. 138 and 139 may be used to obtain an expression for theeffective resistance per unit length (R) of the wire. This gives:$\begin{matrix}{{{R \equiv {{P/\text{<}}I^{2}\text{>}}} = {\frac{\int_{0}^{b}\quad {{{rr}}\quad \sigma {E_{S}}^{2}}}{2\pi {{\int_{0}^{b}\quad {{{rr}}\quad \sigma \quad E_{S}}}}^{2}} = \frac{\int_{0}^{b}\quad {{{rr}}{E_{S}}^{2}}}{2\quad \pi \quad \sigma {{\int_{0}^{b}\quad {{{rr}}\quad E_{S}}}}^{2}}}},} & (140)\end{matrix}$

[2869] with the second term on the right-hand side of EQN. 140 holdingfor constant σ.

[2870] C may be expressed in terms of its real part (C_(R)) itsimaginary part (C_(I))so that:

C=C _(R) +iC _(I).  (141)

[2871] An approximate solution for C_(R) may be obtained. C_(R) may bechosen to be positive. The quantities below may also be needed:

|C|={C _(R) ² +C _(I) ²}^(1/2)  (142)

and γ≡C/|C|=γ _(R) +iγ _(I).  (143)

[2872] A large value of Re(z) gives: $\begin{matrix}{{I_{0}(z)} = {\frac{^{z}}{\sqrt{2\quad \pi \quad z}}{\left\{ {1 + {O\left\lbrack z^{- 1} \right\rbrack}} \right\}.}}} & (144)\end{matrix}$

[2873] This means that:

E _(S)(r)≅E _(s)(b)e ^(−γξ),  (145)

with ξ=|C|(b−r).  (146)

[2874] Substituting EQN. 145 into EQN. 140 yields the approximateresult: $\begin{matrix}{R = {\frac{{C}/2}{2\pi \quad a\quad \sigma \quad \gamma_{R}} = {\frac{{C}^{2}/\left\{ {2C_{R}} \right\}}{2\pi \quad b\quad \sigma}.}}} & (147)\end{matrix}$

[2875] EQN. 147 may be written in the form:

R=1/(2πbδσ),  (148)

with δ=2C _(R) /|C| ² ≅{square root}{square root over (2/(ωμσ))}.  (149)

[2876] δ is known as the skin depth, and the approximate form in EQN.149 arises on replacing σ_(eff) by σ.

[2877] The expression in EQN. 145 may be obtained directly EQN. 135.Transforming to the variable ξ gives: $\begin{matrix}{{{{\frac{1}{1 - {ɛ\quad \xi}}\frac{\partial\quad}{\partial\xi}\left( {\left( {1 - {ɛ\quad \xi}} \right)\frac{\partial E_{S}}{\partial\xi}} \right)} - {\gamma^{2}E_{S}}} = 0},} & (150)\end{matrix}$

 with ε=1/(a|C|).  (151)

[2878] The solution of EQN. 150 can be written as: $\begin{matrix}{{E_{S} = {\sum\limits_{k = 0}^{\infty}{E_{S}^{(k)}ɛ^{k}}}},\quad {with}} & (152) \\{{\frac{\partial^{2}E_{S}^{(0)}}{\partial\xi^{2}} - {\gamma^{2}E_{S}^{(0)}}} = {0\quad {and}}} & (153) \\{{{{\frac{\partial^{2}E_{S}^{(m)}}{\partial\xi^{2}} - {\gamma^{2}E_{S}^{(m)}}} = {\sum\limits_{k = 1}^{m}{\xi^{k - 1}\frac{\partial E_{S}^{m - k}}{\partial\xi}}}};{m = 1}},2,\ldots} & (154)\end{matrix}$

[2879] The solution of EQN. 153 is:

E _(S) ⁽⁰⁾ =E _(S)(a)e ^(−γξ),  (155)

[2880] and solutions of EQN. 154 for successive m may also be readilywritten down. For instance: $\begin{matrix}{E_{S}^{(1)} = {\frac{1}{2}{E_{S}(a)}\xi \quad {^{{- \gamma}\quad \xi}.}}} & (156)\end{matrix}$

[2881] The AC conductance of a composite wire having ferromagneticmaterials may also be solved for analytically. In this case, the region0≦r<a may be composed of material 1 and the region a<r≦b be composed ofmaterial 2. E_(S1)(r) and E_(S2)(r) may denote the electrical fields inthe two regions, respectively. This gives: $\begin{matrix}{{{{{\frac{1}{r}\frac{\partial}{\partial r}\left( {r\frac{\partial E_{S1}}{\partial r}} \right)} - {C_{1}^{2}E_{S1}}} = 0};{0 \leq r < a}}{and}} & (157) \\{{{{{\frac{1}{r}\frac{\partial}{\partial r}\left( {r\frac{\partial E_{S2}}{\partial r}} \right)} - {C_{2}^{2}E_{S2}}} = 0};{a < r \leq b}},} & (158)\end{matrix}$

 with C _(k) =jωμ _(k)σ_(effk) ; k=1, 2  (159)

and σ_(effk)=σ_(k) +jωε _(k) ; k=1, 2.  (160)

[2882] The solutions of EQNS. 157 and 158 satisfy the boundaryconditions:

E _(S1)(a)=E _(S2)(a)  (161)

and H _(S1)(a)=H _(S2)(a)  (162)

[2883] and take the form:

E _(S1)(r)=A ₁ I ₀(C ₁ r)  (163)

and E _(S2)(r)=A ₂ I ₀(C ₂ r)+B ₂ K ₀(C ₂ r).  (164)

[2884] Using EQN. 127, the boundary condition in EQN. 162 may beexpressed in terms of the electric field as: $\begin{matrix}{\left. {\frac{1}{\mu_{1}}\frac{\partial E_{S1}}{\partial r}} \right|_{r = a} = \left. {\frac{1}{\mu_{2}}\frac{\partial E_{S2}}{\partial r}} \middle| {}_{r = a}. \right.} & (165)\end{matrix}$

[2885] Applying the two boundary conditions in EQNS. 161 and 165 allowsE_(S1)(r) and E_(S2)(r) to be expressed in terms of the electric fieldat the surface of the wire E_(S2)(b). EQN. 161 yields:

A ₁ I ₀(C ₁ a)=A ₂ I ₀(C ₂ a)+B ₂ K ₀(C ₂ a),  (166)

[2886] while EQN. 165 gives:

A ₁ {tilde over (C)} ₁ I ₁(C ₁ a)={tilde over (C)} ₂ {A ₂ I ₁(C ₂ a)−B ₂K ₁(C ₂ a)}.  (167)

[2887] Writing EQN. 167 uses the fact that: $\begin{matrix}{{{I_{1}(z)} = {\frac{}{z}{I_{0}(z)}}};{{K_{1}(z)} = {{- \frac{}{z}}{K_{0}(z)}}}} & (168)\end{matrix}$

[2888] and introduces the quantities:

{tilde over (C)} ₁ ≡C ₁/μ₁ ; {tilde over (C)} ₂ ≡C ₂/μ₂.  (169)

[2889] Solving EQN. 166 for A₂ and B₂ in terms of A₁ obtains:$\begin{matrix}{{{A_{2} = {A_{1}\frac{{{\overset{\sim}{C}}_{2}{I_{0}\left( {C_{1}a} \right)}{K_{1}\left( {C_{2}a} \right)}} + {{\overset{\sim}{C}}_{1}{I_{1}\left( {C_{1}a} \right)}{K_{0}\left( {C_{2}a} \right)}}}{{\overset{\sim}{C}}_{2}\left\{ {{{I_{0}\left( {C_{2}a} \right)}{K_{1}\left( {C_{2}a} \right)}} + {{I_{1}\left( {C_{2}a} \right)}{K_{0}\left( {C_{2}a} \right)}}} \right\}}}};}{and}} & (170) \\{B_{2} = {A_{1}{\frac{{{\overset{\sim}{C}}_{2}{I_{0}\left( {C_{1}a} \right)}{I_{1}\left( {C_{2}a} \right)}} - {{\overset{\sim}{C}}_{1}{I_{1}\left( {C_{1}a} \right)}{I_{0}\left( {C_{2}a} \right)}}}{{\overset{\sim}{C}}_{2}\left\{ {{{I_{0}\left( {C_{2}a} \right)}{K_{1}\left( {C_{2}a} \right)}} + {{I_{1}\left( {C_{2}a} \right)}{K_{0}\left( {C_{2}a} \right)}}} \right\}}.}}} & (171)\end{matrix}$

[2890] Power dissipation per unit length and AC resistance of acomposite wire may be solved for similarly to the method used for theuniform wire. In some cases, if the skin depth of the conductor is smallin comparison to the radius of the wire, the functions containing C₂ maybecome large and may be replaced by exponentials. However, as thetemperature nears the Curie temperature, a full solution may berequired.

[2891]FIG. 507 depicts AC resistance versus temperature using theanalytical equations solved for above. The AC resistance has beencalculated for a 244 m long composite wire (outside diameter of 1.52 cm)with a copper core (outside diameter of 0.25 cm) and a carbon steelouter layer (thickness of 0.635 cm). FIG. 507 shows that the ACresistance for this composite wire begins to decrease above about 647°C. and then decreases sharply above about 716° C.

[2892]FIG. 508 depicts an embodiment of freeze well 2756. Freeze well2756 may have first end 3266 at a first location on the surface andsecond end 3268 at a second location on the surface. Freeze well 2756may include first conduit 3270 and second conduit 3272. In certainembodiments, first conduit 3270 and second conduit 3272 may beconcentric, or coaxial, conduits. In one embodiment, as shown in FIG.508, second conduit 3272 is located coaxially within first conduit 3270First conduit 3270 and second conduit 3272 may be made from stainlesssteel or other suitable materials chemically resistant to refrigerant.In some embodiments, first conduit 3270 and second conduit 3272 mayinclude insulated portions in overburden 524. Portions of first conduit3270 and/or portions of second conduit 3272 that are adjacent toun-cooled portions of the formation may include an insulating material(e.g., high density polyethylene) and/or the conduit portions may beinsulated with an insulating material. Portions of first conduit 3270and/or portions of second conduit 3272 that are adjacent to cooledportions of the formation may be formed of a thermally conductivematerial (e.g., copper or a copper alloy). A thermally conductivematerial may enhance heat transfer between the formation and refrigerantin the conduit.

[2893] Refrigerant may be provided to first conduit 3270 at second end3268 of freeze well 2756. Refrigerant may be provided to second conduit3272 at first end 3266 of freeze well 2756. In an embodiment,refrigerant in first conduit 3270 (which flows from second end 3268towards first end 3266) may flow countercurrently to refrigerant insecond conduit 3272 (which flows from first end 3266 towards second end3268). In some embodiments, refrigerant may flow co-currently throughfreeze well 2756 (i.e., refrigerant is provided to first conduit 3270and second conduit 3272 at the same end of the freeze well). Flowingrefrigerant countercurrently in coaxial conduits may more uniformly coolhydrocarbon layer 522 and produce more uniform temperatures in thetreatment area. In addition, a lower pressure in a refrigerant may bemaintained by flowing the refrigerant through a conduit with openings atboth ends of the conduit compare to flowing the refrigerant through aconduit with only one open end. Conduits with only one open endgenerally have a bend or return within the freeze well that may increasea pressure of the refrigerant.

[2894] In some embodiments, refrigerant exiting first conduit 3270and/or second conduit 3272 may be recycled or reused in another freezewell or returned to the same freeze well. For example, refrigerantexiting first conduit 3270 may be provided to second conduit 3272 Incertain embodiments, refrigerant may be compressed before being recycledor reused. In some embodiments, spacers may be positioned at selectedlocations along the length of first conduit 3270 and second conduit 3272to inhibit the conduits from physically contacting each other.

[2895] In certain embodiments, freeze well 2756 may extend intohydrocarbon layer 522 as depicted in FIG. 509. Freeze well 2756 mayinclude a conduit configured positioned in hydrocarbon layer 522.Refrigerant may be provided to the conduit of freeze well 2756. One ormore baffles 3274 may be positioned in annulus 3276 between a wall offreeze well 2756 and hydrocarbon containing layer 522. Baffles 3274 mayinclude rubberized metal, plastic, etc. In some embodiments, baffles3274 may be cement catchers, which may be purchased from Weatherford(Houston, Tex.). Fluids (e.g., water) may flow through hydrocarboncontaining layer 522 through leached/fractured portion 3278 into annulus3276 to overburden 524. Baffles 3274 may inhibit or slow the flow of thefluids in annulus 3276. Slowing the flow rate of water in annulus 3276may increase the rate of cooling of the fluids in the annulus byincreasing the contact time between the fluids and freeze well 2756.Cooling of the fluids may form a low temperature subsurface barrier inhydrocarbon layer 522. In some embodiments, a frozen subsurface barriermay be formed in hydrocarbon layer 522.

[2896] In this patent, certain U.S. patents, U.S. patent applications,and other materials (e.g., articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

[2897] Further modifications and alternative embodiments of variousaspects of the invention may be apparent to those skilled in the art inview of this description. Accordingly, this description is to beconstrued as illustrative only and is for the purpose of teaching thoseskilled in the art the general manner of carrying out the invention. Itis to be understood that the forms of the invention shown and describedherein are to be taken as the presently preferred embodiments. Elementsand materials may be substituted for those illustrated and describedherein, parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims. In addition, it is to understood that featuresdescribed herein independently may, in certain embodiments combined.

What is claimed is:
 1. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least one portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;controlling the heat from the one or more heaters such that an averagetemperature within at least a majority of the selected section of theformation is less than about 375° C.; and producing a mixture from theformation.
 2. The method of claim 1, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 3. The method of claim 1, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range.
 4. Themethod of claim 1, wherein the one or more heaters comprise electricalheaters.
 5. The method of claim 1, wherein the one or more heaterscomprise surface burners.
 6. The method of claim 1, wherein the one ormore heaters comprise flameless distributed combustors.
 7. The method ofclaim 1, wherein the one or more heaters comprise natural distributedcombustors.
 8. The method of claim 1, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 9. The method of claim 1, further comprising controlling apressure within at least a majority of the selected section of theformation with a valve coupled to at least one of the one or moreheaters.
 10. The method of claim 1, further comprising controlling apressure within at least a majority of the selected section of theformation with a valve coupled to a production well located in theformation.
 11. The method of claim 1, further comprising controlling theheat such that an average heating rate of the selected section is lessthan about 1° C. per day during pyrolysis.
 12. The method of claim 1,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity(C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 13. The method of claim 1,wherein allowing the heat to transfer from the one or more heaters tothe selected section comprises transferring heat substantially byconduction.
 14. The method of claim 1, wherein providing heat from theone or more heaters comprises heating the selected section such that athermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 15. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 16. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 17. The method of claim 1, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 18. The method of claim 1, wherein the producedmixture comprises non-condensable hydrocarbons, and wherein about 0.1%by weight to about 15% by weight of the non-condensable hydrocarbons areolefins.
 19. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 20. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 21. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 22. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 23. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, and whereingreater than about 20% by weight of the condensable hydrocarbons arearomatic compounds.
 24. The method of claim 1, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about5% by weight of the condensable hydrocarbons comprises multi-ringaromatics with more than two rings.
 25. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 26. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.27. The method of claim 1, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 28. Themethod of claim 1, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 29. The method of claim 1, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 30. The method of claim 1, further comprising controlling apressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 31. The method of claim 1, further comprising controllingformation conditions such that the produced mixture comprises a partialpressure of H₂ within the mixture greater than about 0.5 bars.
 32. Themethod of claim 31, wherein the partial pressure of H₂ is measured whenthe mixture is at a production well.
 33. The method of claim 1, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 34. The method of claim 1,further comprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 35. The method of claim 1, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 36. The method of claim 1, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 37. The method of claim 1, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 38. The method ofclaim 1, wherein allowing the heat to transfer comprises substantiallyuniformly increasing a permeability of a majority of the selectedsection.
 39. The method of claim 1, further comprising controlling theheat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 40. The method of claim1, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heaters are disposed inthe formation for each production well.
 41. The method of claim 40,wherein at least about 20 heaters are disposed in the formation for eachproduction well.
 42. The method of claim 1, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 43. The method of claim 1, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 44. The methodof claim 1, further comprising separating the produced mixture into agas stream and a liquid stream.
 45. The method of claim 1, furthercomprising separating the produced mixture into a gas stream and aliquid stream and separating the liquid stream into an aqueous streamand a non-aqueous stream.
 46. The method of claim 1, wherein theproduced mixture comprises H₂S, the method further comprising separatinga portion of the H₂S from non-condensable hydrocarbons.
 47. The methodof claim 1, wherein the produced mixture comprises CO₂, the methodfurther comprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 48. The method of claim 1, wherein the mixture is producedfrom a production well, wherein the heating is controlled such that themixture can be produced from the formation as a vapor.
 49. The method ofclaim 1, wherein the mixture is produced from a production well, themethod further comprising heating a wellbore of the production well toinhibit condensation of the mixture within the wellbore.
 50. The methodof claim 1, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the formation adjacent to the wellbore, and furthercomprising heating the formation with the heater element to produce themixture, wherein the mixture comprises a large non-condensablehydrocarbon gas component and H₂.
 51. The method of claim 1, wherein theminimum pyrolysis temperature is about 270° C.
 52. The method of claim1, further comprising maintaining the pressure within the formationabove about 2.0 bars absolute to inhibit production of fluids havingcarbon numbers above
 25. 53. The method of claim 1, further comprisingcontrolling pressure within the formation in a range from aboutatmospheric pressure to about 100 bar, as measured at a wellhead of aproduction well, to control an amount of condensable hydrocarbons withinthe produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons, and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 54.The method of claim 1, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bar, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 55. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least the portion to aselected section of the formation substantially by conduction of heat;pyrolyzing at least some hydrocarbons within the selected section of theformation; and producing a mixture from the formation.
 56. The method ofclaim 55, wherein the one or more heaters comprise at least two heaters,and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 57. The method of claim 55, wherein the one or more heaterscomprise electrical heaters.
 58. The method of claim 55, wherein the oneor more heaters comprise surface burners.
 59. The method of claim 55,wherein the one or more heaters comprise flameless distributedcombustors.
 60. The method of claim 55, wherein the one or more heaterscomprise natural distributed combustors.
 61. The method of claim 55,further comprising controlling a pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 62. The method of claim 55,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1.0° C. per day duringpyrolysis.
 63. The method of claim 55, wherein providing heat from theone or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 64. The method of claim 55, wherein providing heat from the oneor more heaters comprises heating the selected section such that athermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 65. The method of claim 55, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 66. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 67. The method of claim 55, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 68. The method of claim 55, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 69. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 70. The method of claim 55, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 71. The method of claim 55, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 72. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 73. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 74. The method of claim 55, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 75. The method of claim 55, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.76. The method of claim 55, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 77. Themethod of claim 55, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 78. The method of claim 55, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 79. The method of claim 55, further comprising controlling apressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 80. The method of claim 55, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 81. The method of claim 80, wherein the partialpressure of H₂ is measured when the mixture is at a production well. 82.The method of claim 55, further comprising altering a pressure withinthe formation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 83. The method of claim 55,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 84. The methodof claim 55, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 85. The method ofclaim 55, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 86. The method of claim 55, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 87. Themethod of claim 55, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 88. The method of claim 55, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 89. Themethod of claim 55, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 90. The methodof claim 89, wherein at least about 20 heaters are disposed in theformation for each production well.
 91. The method of claim 55, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 92. The method of claim 55,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 93. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 94. The method of claim 93, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 95. The method of claim 93, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 96.The method of claim 93, wherein the one or more heaters compriseelectrical heaters.
 97. The method of claim 93, wherein the one or moreheaters comprise surface burners.
 98. The method of claim 93, whereinthe one or more heaters comprise flameless distributed combustors. 99.The method of claim 93, wherein the one or more heaters comprise naturaldistributed combustors.
 100. The method of claim 93, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 101. The method of claim 93,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 102. The method of claim 93, wherein providing heat from theone or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 103. The method of claim 93, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 104.The method of claim 93, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.105. The method of claim 93, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 106. The methodof claim 93, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15. 107.The method of claim 93, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 108. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 109. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 110. The method of claim 93, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 111. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 112. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 113. The method of claim 93, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 114. The method of claim 93, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.115. The method of claim 93, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 116. Themethod of claim 93, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 117. The method of claim 93, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 118. The method of claim 93, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 119. The method of claim 93, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 120. The method of claim 119, wherein the partialpressure of H₂ is measured when the mixture is at a production well.121. The method of claim 93, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 122. The methodof claim 93, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.123. The method of claim 93, further comprising: providing hydrogen (H₂)to the heated section to hydrogenate hydrocarbons within the section;and heating a portion of the section with heat from hydrogenation. 124.The method of claim 93, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 125. The method of claim 93,wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 126. The method of claim 93, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the selected section.
 127. The method of claim 93,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.128. The method of claim 93, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well.
 129. Themethod of claim 128, wherein at least about 20 heaters are disposed inthe formation for each production well.
 130. The method of claim 93,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 131. The method of claim 93,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 132. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;controlling the heat from the one or more heaters such that an averagetemperature within at least a majority of the selected section of theformation is less than about 370° C. such that production of asubstantial amount of hydrocarbons having carbon numbers greater than 25is inhibited; controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast 2.0 bars; and producing a mixture from the formation, whereinabout 0.1% by weight of the produced mixture to about 15% by weight ofthe produced mixture are olefins, and wherein an average carbon numberof the produced mixture ranges from 1-25.
 133. The method of claim 132,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.134. The method of claim 132, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 135. The method of claim 132, wherein theone or more heaters comprise electrical heaters.
 136. The method ofclaim 132, wherein the one or more heaters comprise surface burners.137. The method of claim 132, wherein the one or more heaters compriseflameless distributed combustors.
 138. The method of claim 132, whereinthe one or more heaters comprise natural distributed combustors. 139.The method of claim 132, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.140. The method of claim 132, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 141. The method of claim 132,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 142. The method of claim 132,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 143. The method of claim 132, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 144. Themethod of claim 132, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 145. The method of claim 132,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 146. The method ofclaim 132, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 147.The method of claim 132, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 148. The method of claim 132, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 149. The method of claim 132, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 150. The method of claim 132, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 151. The method of claim 132, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 152. The method of claim 132, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 153. The method of claim 132, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.154. The method of claim 132, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 155. Themethod of claim 132, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 156. The method of claim 132, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 157. The method of claim 132, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 158. The method of claim 157, wherein the partialpressure of H₂ is measured when the mixture is at a production well.159. The method of claim 132, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 160. The methodof claim 132, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 161. The method ofclaim 132, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 162. The method of claim 132, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 163. Themethod of claim 132, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 164. The method of claim 132, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 165. Themethod of claim 132, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 166. The methodof claim 165, wherein at least about 20 heaters are disposed in theformation for each production well.
 167. The method of claim 132,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 168. The method of claim 132,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 169. The method of claim 132, further comprisingseparating the produced mixture into a gas stream and a liquid stream.170. The method of claim 132, further comprising separating the producedmixture into a gas stream and a liquid stream and separating the liquidstream into an aqueous stream and a non-aqueous stream.
 171. The methodof claim 132, wherein the produced mixture comprises H₂S, the methodfurther comprising separating a portion of the H₂S from non-condensablehydrocarbons.
 172. The method of claim 132, wherein the produced mixturecomprises CO₂, the method further comprising separating a portion of theCO₂ from non-condensable hydrocarbons.
 173. The method of claim 132,wherein the mixture is produced from a production well, wherein theheating is controlled such that the mixture can be produced from theformation as a vapor.
 174. The method of claim 132, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 175. The method of claim 132, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat theformation adjacent to the wellbore, and further comprising heating theformation with the heater element to produce the mixture, wherein theproduced mixture comprise a large non-condensable hydrocarbon gascomponent and H₂.
 176. The method of claim 132, wherein the minimumpyrolysis temperature is about 270° C.
 177. The method of claim 132,further comprising maintaining the pressure within the formation aboveabout 2.0 bars absolute to inhibit production of fluids having carbonnumbers above
 25. 178. The method of claim 132, further comprisingcontrolling pressure within the formation in a range from aboutatmospheric pressure to about 100 bars absolute, as measured at awellhead of a production well, to control an amount of condensablefluids within the produced mixture, wherein the pressure is reduced toincrease production of condensable fluids, and wherein the pressure isincreased to increase production of non-condensable fluids.
 179. Themethod of claim 132, further comprising controlling pressure within theformation in a range from about atmospheric pressure to about 100 barsabsolute, as measured at a wellhead of a production well, to control anAPI gravity of condensable fluids within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 180. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; controlling a pressure within atleast a majority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute; and producing amixture from the formation.
 181. The method of claim 180, whereincontrolling the pressure comprises controlling the pressure with a valvecoupled to at least one of the one or more heaters.
 182. The method ofclaim 180, wherein controlling the pressure comprises controlling thepressure with a valve coupled to a production well located in theformation.
 183. The method of claim 180, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 184. The method of claim 180, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 185.The method of claim 180, wherein the one or more heaters compriseelectrical heaters.
 186. The method of claim 180, wherein the one ormore heaters comprise surface burners.
 187. The method of claim 180,wherein the one or more heaters comprise flameless distributedcombustors.
 188. The method of claim 180, wherein the one or moreheaters comprise natural distributed combustors.
 189. The method ofclaim 180, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 190. The method of claim 180,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 191. The method of claim 180, wherein providing heat from theone or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 192. The method of claim 180, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 193.The method of claim 180, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 194. The method of claim 180, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 195. The method of claim 180, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 196. The method of claim 180, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 197. The method of claim 180, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 198. The method of claim 180, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 199. The method of claim 180,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 200. The method ofclaim 180, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 201. Themethod of claim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 202. The method ofclaim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 203. The method of claim 180, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 204. The methodof claim 180, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 205. The method of claim180, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 206. The method of claim 180, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 207. The method of claim180, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 208. The method of claim 180,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 209. The method ofclaim 208, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 210. The method of claim 180, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 211. The method of claim 180, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 212. The method of claim 180, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 213. The method of claim 180, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 214. The method of claim 180, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 215. The methodof claim 180, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 216. The method of claim 180, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 217. Themethod of claim 180, wherein producing the mixture from the formationcomprises producing the mixture in a production well, and wherein atleast about 7 heaters are disposed in the formation for each productionwell.
 218. The method of claim 217, wherein at least about 20 heatersare disposed in the formation for each production well.
 219. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; and controlling a pressure withinat least a majority of the selected section of the formation, whereinthe controlled pressure is at least about 2.0 bars absolute; controllingthe heat from the one or more heaters such that an average temperaturewithin at least a majority of the selected section of the formation isless than about 375° C.; and producing a mixture from the formation.220. The method of claim 219, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 221. The method of claim 219, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 222.The method of claim 219, wherein the one or more heaters compriseelectrical heaters.
 223. The method of claim 219, wherein the one ormore heaters comprise surface burners.
 224. The method of claim 219,wherein the one or more heaters comprise flameless distributedcombustors.
 225. The method of claim 219, wherein the one or moreheaters comprise natural distributed combustors.
 226. The method ofclaim 219, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 227. The method ofclaim 219, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 228. The method of claim 219, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h *V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 229. The method of claim 219, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 230. The method of claim 219, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 231. The method of claim 219, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 232. The method of claim 219, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 233. The method of claim 219, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.234. The method of claim 219, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 235. The method of claim 219, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 236. The method of claim 219, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 237. The method of claim 219,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 238. The method ofclaim 219, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 239. Themethod of claim 219, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 240. The method ofclaim 219, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 241. The method of claim 219, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 242. The methodof claim 219, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 243. The method of claim219, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 244. The method of claim 219, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 245. The method of claim219, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 246. The method of claim 219,wherein controlling the heat further comprises controlling the heat suchthat coke production is inhibited.
 247. The method of claim 219, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂ withinthe mixture is greater than about 0.5 bars.
 248. The method of claim247, wherein the partial pressure of H₂ is measured when the mixture isat a production well.
 249. The method of claim 219, further comprisingaltering the pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 250. The method of claim 219, wherein controlling formationconditions comprises recirculating a portion of hydrogen from themixture into the formation.
 251. The method of claim 219, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 252. The method of claim 219, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 253. The method of claim 219, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 254. The methodof claim 219, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 255. The method of claim 219, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 256. Themethod of claim 219, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 257. The methodof claim 219, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 258. Themethod of claim 219, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 259. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; producing a mixture from the formation,wherein at least a portion of the mixture is produced during thepyrolysis and the mixture moves through the formation in a vapor phase;and maintaining a pressure within at least a majority of the selectedsection above about 2.0 bars absolute.
 260. The method of claim 259,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.261. The method of claim 259, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 262. The method of claim 259, wherein theone or more heaters comprise electrical heaters.
 263. The method ofclaim 259, wherein the one or more heaters comprise surface burners.264. The method of claim 259, wherein the one or more heaters compriseflameless distributed combustors.
 265. The method of claim 259, whereinthe one or more heaters comprise natural distributed combustors. 266.The method of claim 259, further comprising controlling the pressure anda temperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.267. The method of claim 259, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 268. The method of claim 259,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 269. The method of claim 259,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 270. The method of claim 259, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 271. Themethod of claim 259, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 272. Themethod of claim 259, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 273. The method of claim 259,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 274. The method of claim 259,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 275. The method ofclaim 259, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 276.The method of claim 259, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 277. The method of claim 259, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 278. The method of claim 259, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 279. The method of claim 259, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 280. The method of claim 259, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 281. The method of claim 259, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 282. The method of claim 259, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.283. The method of claim 259, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 284. Themethod of claim 259, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 285. The method of claim 259, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 286. The method of claim 259, wherein the pressure ismeasured at a wellhead of a production well.
 287. The method of claim259, wherein the pressure is measured at a location within a wellbore ofthe production well.
 288. The method of claim 259, wherein the pressureis maintained below about 100 bars absolute.
 289. The method of claim259, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 290. The methodof claim 289, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 291. The method of claim 259, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 292. The method of claim 259, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 293. The method of claim 259, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 294. The method of claim 259, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 295. The method of claim 259, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 296. The methodof claim 259, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 297. The method of claim 259, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 298. Themethod of claim 259, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 299. The methodof claim 259, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 300. Themethod of claim 259, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 301. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; maintaining a pressure within at least amajority of the selected section of the formation above 2.0 barsabsolute; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity higher than an API gravity of condensable hydrocarbons in amixture producible from the formation at the same temperature and atatmospheric pressure.
 302. The method of claim 301, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 303. The method of claim301, wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 304. The method of claim 301, wherein the one or more heaterscomprise electrical heaters.
 305. The method of claim 301, wherein theone or more heaters comprise surface burners.
 306. The method of claim301, wherein the one or more heaters comprise flameless distributedcombustors.
 307. The method of claim 301, wherein the one or moreheaters comprise natural distributed combustors.
 308. The method ofclaim 301, further comprising controlling the pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 309. The method ofclaim 301, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 310. The method of claim 301, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 311. The method of claim 301, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 312. The method of claim 301, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 313. The method of claim 301, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 314. The method of claim 301, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 338. The method of claim 337, wherein at least about 20heaters are disposed in the formation for each production well.
 339. Themethod of claim 301, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern.
 340. Themethod of claim 301, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 341. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; maintaining a pressure within at least amajority of the selected section of the formation to above 2.0 barsabsolute; and producing a fluid from the formation, wherein condensablehydrocarbons within the fluid comprise an atomic hydrogen to atomiccarbon ratio of greater than about 1.75.
 342. The method of claim 341,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.343. The method of claim 341, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 344. The method of claim 341, wherein theone or more heaters comprise electrical heaters.
 345. The method ofclaim 341, wherein the one or more heaters comprise surface burners.346. The method of claim 341, wherein the one or more heaters compriseflameless distributed combustors.
 347. The method of claim 341, whereinthe one or more heaters comprise natural distributed combustors. 348.The method of claim 341, further comprising controlling the pressure anda temperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.349. The method of claim 341, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 350. The method of claim 341,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 351. The method of claim 341,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 352. The method of claim 341, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 353. Themethod of claim 341, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 354. Themethod of claim 341, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 355. The method of claim 341,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 356. The method of claim 341,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 357. The method ofclaim 341, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 358.The method of claim 341, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 359. The method of claim 341, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 360. The method of claim 341, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 361. The method of claim 341, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 362. The method of claim 341, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 363. The method of claim 341, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 364. The method of claim 341, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.365. The method of claim 341, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 366. Themethod of claim 341, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 367. The method of claim 341, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 368. The method of claim 341, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 369. The method of claim 341, wherein the partialpressure of H₂ is measured when the mixture is at a production well.370. The method of claim 341, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 371. The methodof claim 341, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.372. The method of claim 341, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 373. The method of claim 341, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 374. Themethod of claim 341, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 375. The method of claim 341, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 376.The method of claim 341, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 377. The method of claim 341, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 378. The method of claim 341, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 379. The method of claim 341,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 380. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;maintaining a pressure within at least a majority of the selectedsection of the formation to above 2.0 bars absolute; and producing amixture from the formation, wherein the produced mixture comprises ahigher amount of non-condensable components as compared tonon-condensable components producible from the formation under the sametemperature conditions and at atmospheric pressure.
 381. The method ofclaim 380, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 382. The method of claim 380, wherein controlling formationconditions comprises maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 383. The method of claim380, wherein the one or more heaters comprise electrical heaters. 384.The method of claim 380, wherein the one or more heaters comprisesurface burners.
 385. The method of claim 380, wherein the one or moreheaters comprise flameless distributed combustors.
 386. The method ofclaim 380, wherein the one or more heaters comprise natural distributedcombustors.
 387. The method of claim 380, further comprising controllingthe pressure and a temperature within at least a majority of theselected section of the formation, wherein the pressure is controlled asa function of temperature, or the temperature is controlled as afunction of pressure.
 388. The method of claim 380, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 389. Themethod of claim 380, wherein providing heat from the one or more heatersto at least the portion of formation comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from the one or moreheaters, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/day (Pwr)provided to the selected volume is equal to or less thanh*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, and wherein anaverage heating rate (h) of the selected volume is about 10° C./day.390. The method of claim 380, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 391. The methodof claim 380, wherein providing heat from the one or more heaterscomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 392. The method of claim 380, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 393. The method of claim 380, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 394.The method of claim 380, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 395. Themethod of claim 380, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 396. The method of claim 380, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 397. The method of claim 380, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 398. The method of claim 380,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 399. The method ofclaim 380, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 400. Themethod of claim 380, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 401. The method ofclaim 380, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 402. The method of claim 380, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 403. The methodof claim 380, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 404. The method of claim380, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 405. The method of claim 380, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 406. The method of claim380, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 407. The method of claim 380,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 408. The method ofclaim 380, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 409. The method of claim 380, furthercomprising altering the pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 410. The method of claim 380, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 411. The method of claim 380, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 412. The method of claim 380, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 413. The methodof claim 380, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 414. The method of claim 380, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 415. Themethod of claim 380, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 416. The methodof claim 380, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 417. Themethod of claim 380, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 418. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation such that superimposed heat from the one ormore heaters pyrolyzes at least about 20% by weight of hydrocarbonswithin the selected section of the formation; and producing a mixturefrom the formation.
 419. The method of claim 418, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 420. The method of claim418, wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 421. The method of claim 418, wherein the one or more heaterscomprise electrical heaters.
 422. The method of claim 418, wherein theone or more heaters comprise surface burners.
 423. The method of claim418, wherein the one or more heaters comprise flameless distributedcombustors.
 424. The method of claim 418, wherein the one or moreheaters comprise natural distributed combustors.
 425. The method ofclaim 418, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 426. The method ofclaim 418, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 427. The method of claim 418, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 428. The method of claim 418, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 429. The method of claim 418, wherein providing heat fromthe one or more heaters comprises heating the selected formation suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 430. The method of claim418, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 431. The method of claim418, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 432. The method of claim 418,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 433. The method of claim 418,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 434. The method ofclaim 418, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 435.The method of claim 418, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 436. The method of claim 418, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 437. The method of claim 418, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 438. The method of claim 418, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 439. The method of claim 418, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 440. The method of claim 418, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 441. The method of claim 418, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.442. The method of claim 418, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 443. Themethod of claim 418, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 444. The method of claim 418, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 445. The method of claim 418, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 446. The method of claim 418, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 447. The method of claim 418, wherein a partialpressure of H₂ is measured when the mixture is at a production well.448. The method of claim 418, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 449. The methodof claim 418, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.450. The method of claim 418, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 451. The method of claim 418, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 452. Themethod of claim 418, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 453. The method of claim 418, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 454.The method of claim 418, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 455. The method of claim 418, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 456. The method of claim 455, wherein at leastabout 20 heaters are disposed in the formation for each production well.457. The method of claim 418, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.458. The method of claim 418, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 459. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation such that superimposed heat from theone or more heaters pyrolyzes at least about 20% of hydrocarbons withinthe selected section of the formation; and producing a mixture from theformation, wherein the mixture comprises a condensable component havingan API gravity of at least about 25°.
 460. The method of claim 459,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.461. The method of claim 459, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 462. The method of claim 459, wherein theone or more heaters comprise electrical heaters.
 463. The method ofclaim 459, wherein the one or more heaters comprise surface burners.464. The method of claim 459, wherein the one or more heaters compriseflameless distributed combustors.
 465. The method of claim 459, whereinthe one or more heaters comprise natural distributed combustors. 466.The method of claim 459, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.467. The method of claim 459, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 468. The method of claim 459,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 469. The method of claim 459,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 470. The method of claim 459, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 471. Themethod of claim 459, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 472. The method of claim 459,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 473. The method of claim 459,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 474. The method ofclaim 459, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 475.The method of claim 459, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 476. The method of claim 459, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 477. The method of claim 459, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 478. The method of claim 459, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 479. The method of claim 459, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 480. The method of claim 459, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 481. The method of claim 459, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.482. The method of claim 459, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 483. Themethod of claim 459, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 484. The method of claim 459, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 485. The method of claim 459, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 486. The method of claim 459, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 487. The method of claim 459, wherein a partialpressure of H₂ is measured when the mixture is at a production well.488. The method of claim 459, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 489. The methodof claim 459, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.490. The method of claim 459, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 491. The method of claim 459, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 492. Themethod of claim 459, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 493. The method of claim 459, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 494.The method of claim 459, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 495. The method of claim 459, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 496. The method of claim 495, wherein at leastabout 20 heaters are disposed in the formation for each production well.497. The method of claim 459, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.498. The method of claim 459, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 499. A method oftreating a layer of a hydrocarbon containing formation in situ,comprising: providing heat from one or more heaters to at least aportion of the layer, wherein the one or more heaters are positionedproximate an edge of the layer; allowing the heat to transfer from theone or more heaters to a selected section of the layer such thatsuperimposed heat from the one or more heaters pyrolyzes at least somehydrocarbons within the selected section of the formation; and producinga mixture from the formation.
 500. The method of claim 499, wherein theone or more heaters are laterally spaced from a center of the layer.501. The method of claim 499, wherein the one or more heaters arepositioned in a staggered line.
 502. The method of claim 499, whereinthe one or more heaters positioned proximate the edge of the layer canincrease an amount of hydrocarbons produced per unit of energy input tothe one or more heaters.
 503. The method of claim 499, wherein the oneor more heaters positioned proximate the edge of the layer can increasethe volume of formation undergoing pyrolysis per unit of energy input tothe one or more heaters.
 504. The method of claim 499, wherein the oneor more heaters comprise electrical heaters.
 505. The method of claim499, wherein the one or more heaters comprise surface burners.
 506. Themethod of claim 499, wherein the one or more heaters comprise flamelessdistributed combustors.
 507. The method of claim 499, wherein the one ormore heaters comprise natural distributed combustors.
 508. The method ofclaim 499, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 509. The method ofclaim 499, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1.0° C. per dayduring pyrolysis.
 510. The method of claim 499, wherein providing heatfrom the one or more heaters to at least the portion of the layercomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 511. The method of claim 499, wherein providingheat from the one or more heaters comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 512. The method of claim499, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 513. The method of claim499, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 514. The method of claim 499,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 515. The method ofclaim 499, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 516.The method of claim 499, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 517. The method of claim 499, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 518. The method of claim 499, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 519. The method of claim 499, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 520. The method of claim 499, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 521. The method of claim 499, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 522. The method of claim 499, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.523. The method of claim 499, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 524. Themethod of claim 499, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 525. The method of claim 499, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 526. The method of claim 499, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 527. The method of claim 499, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 528. The method of claim 527, wherein the partialpressure of H₂ is measured when the mixture is at a production well.529. The method of claim 499, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 530. The methodof claim 499, further comprising controlling formation conditions,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 531. The methodof claim 499, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 532. The method ofclaim 499, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 533. The method of claim 499, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 534. Themethod of claim 499, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 535. The method of claim 499, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 536. Themethod of claim 499, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 537. The methodof claim 536, wherein at least about 20 heaters are disposed in theformation for each production well.
 538. The method of claim 499,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 539. The method of claim 499,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 540. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure; and producing a mixture from theformation.
 541. The method of claim 540, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 542. The method of claim 540, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 543.The method of claim 540, wherein the one or more heaters compriseelectrical heaters.
 544. The method of claim 540, wherein the one ormore heaters comprise surface burners.
 545. The method of claim 540,wherein the one or more heaters comprise flameless distributedcombustors.
 546. The method of claim 540, wherein the one or moreheaters comprise natural distributed combustors.
 547. The method ofclaim 540, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 548. The method of claim 540, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (Cν), and wherein the heating pyrolyzes at leastsome hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 549. The method of claim 540, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 550. The method of claim 540, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 551. The method of claim 540, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 552. The method of claim 540, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 553. The method of claim 540, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.554. The method of claim 540, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 555. The method of claim 540, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 556. The method of claim 540, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 557. The method of claim 540,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 558. The method ofclaim 540, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 559. Themethod of claim 540, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 560. The method ofclaim 540, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 561. The method of claim 540, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 562. The methodof claim 540, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 563. The method of claim540, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 564. The method of claim 540, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 565. The method of claim540, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 566. The method of claim 540,wherein the controlled pressure is at least about 2.0 bars absolute.567. The method of claim 540, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 568. The method of claim 540, wherein a partial pressureof H₂ is measured when the mixture is at a production well.
 569. Themethod of claim 540, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 570. The method of claim540, wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 571. The methodof claim 540, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 572. The method ofclaim 540, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 573. The method of claim 540, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 574. Themethod of claim 540, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 575. The method of claim 540, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 576. Themethod of claim 540, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 577. The methodof claim 576, wherein at least about 20 heaters are disposed in theformation for each production well.
 578. The method of claim 540,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 579. The method of claim 540,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 580. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation toraise an average temperature within the selected section to, or above, atemperature that will pyrolyze hydrocarbons within the selected section;producing a mixture from the formation; and controlling API gravity ofthe produced mixture to be greater than about 25 degrees API bycontrolling average pressure and average temperature in the selectedsection such that the average pressure in the selected section isgreater than the pressure (p) set forth in the following equation for anassessed average temperature (T) in the selected section: p=e^([−44000/T+67]) where p is measured in psia and T is measured in °Kelvin.
 581. The method of claim 580, wherein the API gravity of theproduced mixture is controlled to be greater than about 30 degrees API,and wherein the equation is: p=e ^([−31000/T+51]).
 582. The method ofclaim 580, wherein the API gravity of the produced mixture is controlledto be greater than about 35 degrees API, and wherein the equation is:p=e ^([−220001/T+38]).
 583. The method of claim 580, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 584. The method of claim580, wherein controlling the average temperature comprises maintaining atemperature in the selected section within a pyrolysis temperaturerange.
 585. The method of claim 580, wherein the one or more heaterscomprise electrical heaters.
 586. The method of claim 580, wherein theone or more heaters comprise surface burners.
 587. The method of claim580, wherein the one or more heaters comprise flameless distributedcombustors.
 588. The method of claim 580, wherein the one or moreheaters comprise natural distributed combustors.
 589. The method ofclaim 580, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 590. The method of claim 580,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 591. The method of claim 580, wherein providing heat from theone or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 592. The method of claim 580, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 593.The method of claim 580, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 594. The method of claim 580, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 595. The method of claim 580, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.596. The method of claim 580, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 597. The method of claim 580, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 598. The method of claim 580, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 599. The method of claim 580,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 600. The method ofclaim 580, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 601. Themethod of claim 580, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 602. The method ofclaim 580, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 603. The method of claim 580, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 604. The methodof claim 580, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 605. The method of claim580, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 606. The method of claim 580, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 607. The method of claim580, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 608. The method of claim 580,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 609. The method ofclaim 580, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 610. The method of claim 580, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 611. The method of claim 580, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 612. The method of claim 580, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 613. The method of claim 580, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 614. The method of claim 580, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 615. The methodof claim 580, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 616. The method of claim 580, wherein the heat iscontrolled to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 617. The method of claim580, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heaters are disposed inthe formation for each production well.
 618. The method of claim 617,wherein at least about 20 heaters are disposed in the formation for eachproduction well.
 619. The method of claim 580, further comprisingproviding heat from three or more heaters to at least a portion of theformation, wherein three or more of the heaters are located in theformation in a unit of heaters, and wherein the unit of heaterscomprises a triangular pattern.
 620. The method of claim 580, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 621. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat to at least a portion of ahydrocarbon containing formation such that a temperature (T) in asubstantial part of the heated portion exceeds 270° C. and hydrocarbonsare pyrolyzed within the heated portion of the formation; controlling apressure (p) within at least a substantial part of the heated portion ofthe formation; wherein p_(bar)>e^([(−A/T)+B−2.6744]); wherein p is thepressure in bars absolute and T is the temperature in degrees K, and Aand B are parameters that are larger than 10 and are selected inrelation to the characteristics and composition of the hydrocarboncontaining formation and on the required olefin content and carbonnumber of the pyrolyzed hydrocarbon fluids; and producing pyrolyzedhydrocarbon fluids from the heated portion of the formation.
 622. Themethod of claim 621, wherein A is greater than 14000 and B is greaterthan about 25 and a majority of the produced pyrolyzed hydrocarbonfluids have an average carbon number lower than 25 and comprise lessthan about 10% by weight of olefins.
 623. The method of claim 621,wherein T is less than about 390° C., p is greater than about 1.4 bar, Ais greater than about 44000, and b is greater than about 67, and amajority of the produced pyrolyzed hydrocarbon fluids have an averagecarbon number less than 25 and comprise less than 10% by weight ofolefins.
 624. The method of claim 621, wherein T is less than about 390°C., p is greater than about 2 bar, A is less than about 57000, and b isless than about 83, and a majority of the produced pyrolyzed hydrocarbonfluids have an average carbon number lower than about
 21. 625. Themethod of claim 621, further comprising controlling the heat such thatan average heating rate of the heated portion is less than about 3° C.per day during pyrolysis.
 626. The method of claim 621, whereinproviding heat from the one or more heaters to at least the portion offormation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heaters, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 627. The method of claim 621, wherein heat istransferred substantially by conduction from one or more heaters locatedin one or more heaters to the heated portion of the formation.
 628. Themethod of claim 621, further comprising controlling formation conditionsto produce a mixture of hydrocarbon fluids and H₂, wherein a partialpressure of H₂ within the mixture flowing through the formation isgreater than 0.5 bars.
 629. The method of claim 628, further comprising,hydrogenating a portion of the produced pyrolyzed hydrocarbon fluidswith at least a portion of the produced hydrogen and heating the fluidswith heat from hydrogenation.
 630. The method of claim 621, wherein thehydrocarbon containing formation is a coal seam and at least about 70%of the hydrocarbon content of the coal, when such hydrocarbon content ismeasured by a Fischer assay, is produced from the heated portion of theformation.
 631. The method of claim 621, wherein the substantiallygaseous pyrolyzed hydrocarbon fluids are produced from a productionwell, the method further comprising heating a wellbore of the productionwell to inhibit condensation of the hydrocarbon fluids within thewellbore.
 632. A method of treating a hydrocarbon containing formationin situ, comprising: providing heat from one or more heaters to at leasta portion of the formation; allowing the heat to transfer from the oneor more heaters to a selected section of the formation to raise anaverage temperature within the selected section to, or above, atemperature that will pyrolyze hydrocarbons within the selected section;producing a mixture from the formation; and controlling a weightpercentage of olefins of the produced mixture to be less than about 20%by weight by controlling average pressure and average temperature in theselected section such that the average pressure in the selected sectionis greater than the pressure (p) set forth in the following equation foran assessed average temperature (T) in the selected section: p=e^([−57000/T+83]) where p is measured in psia and T is measured in °Kelvin.
 633. The method of claim 632, wherein the weight percentage ofolefins of the produced mixture is controlled to be less than about 10%by weight, and wherein the equation is: p=e ^([−16000/T+28]).
 634. Themethod of claim 632, wherein the weight percentage of olefins of theproduced mixture is controlled to be less than about 5% by weight, andwherein the equation is: p=e ^(−12000/T+22]).
 635. The method of claim632, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.636. The method of claim 632, wherein the one or more heaters compriseelectrical heaters.
 637. The method of claim 632, wherein the one ormore heaters comprise surface burners.
 638. The method of claim 632,wherein the one or more heaters comprise flameless distributedcombustors.
 639. The method of claim 632, wherein the one or moreheaters comprise natural distributed combustors.
 640. The method ofclaim 632, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 641. The method of claim 640,wherein controlling an average temperature comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 642. The method of claim 632, further comprising controlling theheat such that an average heating rate of the selected section is lessthan about 3.0° C. per day during pyrolysis.
 643. The method of claim632, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 644. The method of claim 632, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 645. The method of claim 632, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 646. The method of claim 632, wherein providing heat fromthe one or more heaters comprises heating the selected formation suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 647. The method of claim632, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 648. The method of claim632, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 649. The method of claim 632,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 650. The method of claim 632,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 651. The method ofclaim 632, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 652.The method of claim 632, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 653. The method of claim 632, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 654. The method of claim 632, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 655. The method of claim 632, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 656. The method of claim 632, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 657. The method of claim 632, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 658. The method of claim 632, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.659. The method of claim 632, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 660. Themethod of claim 632, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 661. The method of claim 632, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 662. The method of claim 632, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 663. The method of claim 632, wherein the partialpressure of H₂ is measured when the mixture is at a production well.664. The method of claim 632, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 665. The methodof claim 632, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.666. The method of claim 632, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 667. The method of claim 632, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 668. Themethod of claim 632, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 669. The method of claim 632, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 670.The method of claim 632, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 671. The method of claim 632, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 672. The method of claim 632, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 673. The method of claim 632,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 674. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation toraise an average temperature within the selected section to, or above, atemperature that will pyrolyze hydrocarbons within the selected section;producing a mixture from the formation; and controlling hydrocarbonshaving carbon numbers greater than 25 of the produced mixture to be lessthan about 25% by weight by controlling average pressure and averagetemperature in the selected section such that the average pressure inthe selected section is greater than the pressure (p) set forth in thefollowing equation for an assessed average temperature (T) in theselected section: p=e ^([−14000/T+25]) where p is measured in psia and Tis measured in ° Kelvin.
 675. The method of claim 674, wherein thehydrocarbons having carbon numbers greater than 25 of the producedmixture is controlled to be less than about 20% by weight, and whereinthe equation is: p=e ^([−16000/T+28]).
 676. The method of claim 674,wherein the hydrocarbons having carbon numbers greater than 25 of theproduced mixture is controlled to be less than about 15% by weight, andwherein the equation is: p=e ^([−18000/T+32]).
 677. The method of claim674, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.678. The method of claim 674, wherein the one or more heaters compriseelectrical heaters.
 679. The method of claim 674, wherein the one ormore heaters comprise surface burners.
 680. The method of claim 674,wherein the one or more heaters comprise flameless distributedcombustors.
 681. The method of claim 674, wherein the one or moreheaters comprise natural distributed combustors.
 682. The method ofclaim 674, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 683. The method of claim 682,wherein controlling the temperature comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 684.The method of claim 674, further comprising controlling the heat suchthat an average heating rate of the selected section is less than about1° C. per day during pyrolysis.
 685. The method of claim 674, whereinproviding heat from the one or more heaters to at least the portion offormation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heaters, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 686. The method of claim 674, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 687. The method of claim 674, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 688. The method of claim 674, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 689. The method of claim 674, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 690. The method of claim 674, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 691. The method of claim 674, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 692. The method of claim 674, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 693. The method of claim 674,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 694. The method ofclaim 674, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 695. Themethod of claim 674, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 696. The method ofclaim 674, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 697. The method of claim 674, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 698. The methodof claim 674, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 699. The method of claim674, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 700. The method of claim 674, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 701. The method of claim674, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 702. The method of claim 674,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 703. The method ofclaim 674, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 704. The method of claim 674, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 705. The method of claim 674, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 706. The method of claim 674, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 707. The method of claim 674, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 708. The methodof claim 674, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 709. The method of claim 674, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 710. Themethod of claim 674, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 711. The methodof claim 710, wherein at least about 20 heaters are disposed in theformation for each production well.
 712. The method of claim 674,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 713. The method of claim 674,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 714. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation toraise an average temperature within the selected section to, or above, atemperature that will pyrolyze hydrocarbons within the selected section;producing a mixture from the formation; and controlling an atomichydrogen to carbon ratio of the produced mixture to be greater thanabout 1.7 by controlling average pressure and average temperature in theselected section such that the average pressure in the selected sectionis greater than the pressure (p) set forth in the following equation foran assessed average temperature (T) in the selected section: p=e^([−38000/T+61]) where p is measured in psia and T is measured in °Kelvin.
 715. The method of claim 714, wherein the atomic hydrogen tocarbon ratio of the produced mixture is controlled to be greater thanabout 1.8, and wherein the equation is: p=e ^([−13000/T+24]).
 716. Themethod of claim 714, wherein the atomic hydrogen to carbon ratio of theproduced mixture is controlled to be greater than about 1.9, and whereinthe equation is: p=e ^([−8000/T+18]).
 717. The method of claim 714,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.718. The method of claim 714, wherein the one or more heaters compriseelectrical heaters.
 719. The method of claim 714, wherein the one ormore heaters comprise surface burners.
 720. The method of claim 714,wherein the one or more heaters comprise flameless distributedcombustors.
 721. The method of claim 714, wherein the one or moreheaters comprise natural distributed combustors.
 722. The method ofclaim 714, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 723. The method of claim 722,wherein controlling the temperature comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 724.The method of claim 714, further comprising controlling the heat suchthat an average heating rate of the selected section is less than about1° C. per day during pyrolysis.
 725. The method of claim 714, whereinproviding heat from the one or more heaters to at least the portion offormation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heaters, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 726. The method of claim 714, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 727. The method of claim 714, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 728. The method of claim 714, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 729. The method of claim 714, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 730. The method of claim 714, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.731. The method of claim 714, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 732. The method of claim 714, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 733. The method of claim 714, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 734. The method of claim 714,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 735. The method ofclaim 714, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 736. Themethod of claim 714, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 737. The method ofclaim 714, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 738. The method of claim 714, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 739. The methodof claim 714, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 740. The method of claim714, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 741. The method of claim 714, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 742. The method of claim714, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 743. The method of claim 714,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 744. The method ofclaim 714, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 745. The method of claim 714, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 746. The method of claim 714, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 747. The method of claim 714, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 748. The method of claim 714, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 749. The method of claim 714, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 750. The methodof claim 714, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 751. The method of claim 714, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 752. Themethod of claim 714, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 753. The methodof claim 714, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 754. Themethod of claim 714, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 755. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least one portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; controlling a pressure-temperaturerelationship within at least the selected section of the formation byselected energy input into the one or more heaters and by pressurerelease from the selected section through wellbores of the one or moreheaters; and producing a mixture from the formation.
 756. The method ofclaim 755, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 757. The method of claim 755, wherein the one or more heaterscomprise at least two heaters.
 758. The method of claim 755, wherein theone or more heaters comprise surface burners.
 759. The method of claim755, wherein the one or more heaters comprise flameless distributedcombustors.
 760. The method of claim 755, wherein the one or moreheaters comprise natural distributed combustors.
 761. The method ofclaim 755, further comprising controlling the pressure-temperaturerelationship by controlling a rate of removal of fluid from theformation.
 762. The method of claim 755, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 763. The method of claim755, wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 764. The method of claim 755,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 765. The method of claim 755, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 766. Themethod of claim 755, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 767. Themethod of claim 755, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 768. The method of claim 755,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 769. The method of claim 755,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 770. The method ofclaim 755, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 771.The method of claim 755, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 772. The method of claim 755, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 773. The method of claim 755, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 774. The method of claim 755, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 775. The method of claim 755, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 776. The method of claim 755, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 777. The method of claim 755, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.778. The method of claim 755, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 779. Themethod of claim 755, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 780. The method of claim 755, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 781. The method of claim 755, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 782. The method of claim 755, further comprising controllingformation conditions to produce a mixture of hydrocarbon fluids and H₂,wherein the partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 783. The method of claim 755, further comprisingcontrolling formation conditions to produce a mixture of condensablehydrocarbons and H₂, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bars.
 784. The method of claim 755, wherein apartial pressure of H₂ is measured when the mixture is at a productionwell.
 785. The method of claim 755, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 786. Themethod of claim 755, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.787. The method of claim 755, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 788. The method of claim 755, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 789. Themethod of claim 755, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 790. The method of claim 755, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 791.The method of claim 755, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 792. The method of claim 755, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 793. The method of claim 792, wherein at leastabout 20 heaters are disposed in the formation for each production well.794. The method of claim 755, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.795. The method of claim 755, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 796. A method oftreating a hydrocarbon containing formation in situ, comprising: heatinga selected volume (V) of the hydrocarbon containing formation, whereinformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 797. The method of claim 796,wherein heating a selected volume comprises heating with an electricalheater.
 798. The method of claim 796, wherein heating a selected volumecomprises heating with a surface burner.
 799. The method of claim 796,wherein heating a selected volume comprises heating with a flamelessdistributed combustor.
 800. The method of claim 796, wherein heating aselected volume comprises heating with at least one natural distributedcombustor.
 801. The method of claim 796, further comprising controllinga pressure and a temperature within at least a majority of the selectedvolume of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 802. The method of claim 796, further comprisingcontrolling the heating such that an average heating rate of theselected volume is less than about 1° C. per day during pyrolysis. 803.The method of claim 796, wherein a value for C_(v) is determined as anaverage heat capacity of two or more samples taken from the hydrocarboncontaining formation.
 804. The method of claim 796, wherein heating theselected volume comprises transferring heat substantially by conduction.805. The method of claim 796, wherein heating the selected volumecomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 806. The method of claim 796, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 807. The method of claim 796, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 808.The method of claim 796, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 809. Themethod of claim 796, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 810. The method of claim 796, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 811. The method of claim 796, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 812. The method of claim 796,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 813. The method ofclaim 796, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 814. Themethod of claim 796, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 815. The method ofclaim 796, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 816. The method of claim 796, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 817. The methodof claim 796, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 818. The method of claim796, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 819. The method of claim 796, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 820. The method of claim796, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer
 821. The method of claim 796,further comprising controlling a pressure within at least a majority ofthe selected volume of the formation, wherein the controlled pressure isat least about 2.0 bars absolute.
 822. The method of claim 796, furthercomprising controlling formation conditions to produce a mixture fromthe formation comprising condensable hydrocarbons and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 823. The method of claim 796, wherein a partial pressure of H₂ ismeasured when the mixture is at a production well.
 824. The method ofclaim 796, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 825. The method of claim 796, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 826. The method of claim796, further comprising: providing hydrogen (H₂) to the heated volume tohydrogenate hydrocarbons within the volume; and heating a portion of thevolume with heat from hydrogenation.
 827. The method of claim 796,wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 828. The method of claim 796, further comprisingincreasing a permeability of a majority of the selected volume togreater than about 100 millidarcy.
 829. The method of claim 796, furthercomprising substantially uniformly increasing a permeability of amajority of the selected volume.
 830. The method of claim 796, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by the Fischer Assay.831. The method of claim 796, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well.
 832. Themethod of claim 831, wherein at least about 20 heaters are disposed inthe formation for each production well.
 833. The method of claim 796,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 834. The method of claim 796,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 835. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation toraise an average temperature within the selected section to, or above, atemperature that will pyrolyze hydrocarbons within the selected section;controlling heat output from the one or more heaters such that anaverage heating rate of the selected section rises by less than about 3°C. per day when the average temperature of the selected section is at,or above, the temperature that will pyrolyze hydrocarbons within theselected section; and producing a mixture from the formation.
 836. Themethod of claim 835, wherein controlling heat output comprises: raisingthe average temperature within the selected section to a firsttemperature that is at or above a minimum pyrolysis temperature ofhydrocarbons within the formation; limiting energy input into the one ormore heaters to inhibit increase in temperature of the selected section;and increasing energy input into the formation to raise an averagetemperature of the selected section above the first temperature whenproduction of formation fluid declines below a desired production rate.837. The method of claim 835, wherein controlling heat output comprises:raising the average temperature within the selected section to a firsttemperature that is at or above a minimum pyrolysis temperature ofhydrocarbons within the formation; limiting energy input into the one ormore heaters to inhibit increase in temperature of the selected section;and increasing energy input into the formation to raise an averagetemperature of the selected section above the first temperature whenquality of formation fluid produced from the formation falls below adesired quality.
 838. The method of claim 835, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section.
 839. The method of claim 835, wherein theone or more heaters comprise electrical heaters.
 840. The method ofclaim 835, wherein the one or more heaters comprise surface burners.841. The method of claim 835, wherein the one or more heaters compriseflameless distributed combustors.
 842. The method of claim 835, whereinthe one or more heaters comprise natural distributed combustors. 843.The method of claim 835, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.844. The method of claim 835, wherein the heat is controlled such thatan average heating rate of the selected section is less than about 1.5°C. per day during pyrolysis.
 845. The method of claim 835, wherein theheat is controlled such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 846. Themethod of claim 835, wherein providing heat from the one or more heatersto at least the portion of formation comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from the one or moreheaters, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/day (Pwr)provided to the selected volume is equal to or less thanh*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, and wherein anaverage heating rate (h) of the selected volume is about 10° C./day.847. The method of claim 835, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 848. The methodof claim 835, wherein providing heat from the one or more heaterscomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 849. The method of claim 835, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 850. The method of claim 835, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 851.The method of claim 835, wherein the produced mixture comprisescondensable hydrocarbons, wherein the condensable hydrocarbons have anolefin content less than about 2.5% by weight of the condensablehydrocarbons, and wherein the olefin content is greater than about 0.1%by weight of the condensable hydrocarbons.
 852. The method of claim 835,wherein the produced mixture comprises non-condensable hydrocarbons,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.15, and wherein the ratio of ethene toethane is greater than about 0.001.
 853. The method of claim 835,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.10 and wherein the ratio of ethene toethane is greater than about 0.001.
 854. The method of claim 835,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.05 and wherein the ratio of ethene toethane is greater than about 0.001.
 855. The method of claim 835,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 856. The method ofclaim 835, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 857. Themethod of claim 835, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 858. Themethod of claim 835, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 859. Themethod of claim 835, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 860. The method ofclaim 835, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 861. The method of claim 835, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 862. The methodof claim 835, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 863. The method of claim835, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 864. The method of claim 835, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 865. The method of claim835, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 866. The method of claim 835,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 867. The method of claim 835,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 868. The method ofclaim 835, wherein a partial pressure of H₂ is measured when the mixtureis at a production well.
 869. The method of claim 835, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 870. The method of claim 835, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 871. The method of claim 835, furthercomprising: providing H₂ to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 872. The method of claim 835, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 873. The method of claim 835, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 874. The methodof claim 835, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 875. The method of claim 835, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 876. Themethod of claim 835, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 877. The methodof claim 876, wherein at least about 20 heaters are disposed in theformation for each production well.
 878. The method of claim 835,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 879. The method of claim 835,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 880. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; to heat a selected section ofthe formation to an average temperature above about 270° C.; allowingthe heat to transfer from the one or more heaters to the selectedsection of the formation; controlling the heat from the one or moreheaters such that an average heating rate of the selected section isless than about 3° C. per day during pyrolysis; and producing a mixturefrom the formation.
 881. The method of claim 880, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 882. The method of claim880, wherein the one or more heaters comprise electrical heaters. 883.The method of claim 880, further comprising supplying electricity to theelectrical heaters substantially during non-peak hours.
 884. The methodof claim 880, wherein the one or more heaters comprise surface burners.885. The method of claim 880, wherein the one or more heaters compriseflameless distributed combustors.
 886. The method of claim 880, whereinthe one or more heaters comprise natural distributed combustors. 887.The method of claim 880, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.888. The method of claim 880, wherein the heat is further controlledsuch that an average heating rate of the selected section is less thanabout 3° C./day until production of condensable hydrocarbonssubstantially ceases.
 889. The method of claim 880, wherein the heat isfurther controlled such that an average heating rate of the selectedsection is less than about 1.5° C. per day during pyrolysis.
 890. Themethod of claim 880, wherein the heat is further controlled such that anaverage heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 891. The method of claim 880, whereinproviding heat from the one or more heaters to at least the portion offormation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heaters, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 892. The method of claim 880, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 893. The method of claim 880, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 894. The method of claim 880, whereinthe produced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 895. The method of claim 880, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 896. The method of claim 880, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.897. The method of claim 880, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 898. Themethod of claim 880, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 899.The method of claim 880, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 900. The method of claim 880, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 901. The method of claim 880, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 902. The method of claim 880, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 903. The method of claim 880, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 904. The method of claim 880, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 905. The method of claim 880, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.906. The method of claim 880, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 907. Themethod of claim 880, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 908. The method of claim 880, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 909. The method of claim 880, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 910. The method of claim 880, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 911. The method of claim 910, wherein the partialpressure of H₂ is measured when the mixture is at a production well.912. The method of claim 880, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 913. The methodof claim 880, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.914. The method of claim 880, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 915. The method of claim 880, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 916. Themethod of claim 880, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 917. The method of claim 880, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 918.The method of claim 880, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 919. The method of claim 880, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 920. The method of claim 919, wherein at leastabout 20 heaters are disposed in the formation for each production well.921. The method of claim 880, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.922. The method of claim 880, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 923. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; producing a mixture from theformation through at least one production well; monitoring a temperatureat or in the production well; and controlling heat input to raise themonitored temperature at a rate of less than about 3° C. per day. 924.The method of claim 923, wherein the one or more heaters comprise atleast two heaters, and wherein superposition of heat from at least thetwo heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 925. The method of claim 923, wherein the oneor more heaters comprise electrical heaters.
 926. The method of claim923, wherein the one or more heaters comprise surface burners.
 927. Themethod of claim 923, wherein the one or more heaters comprise flamelessdistributed combustors.
 928. The method of claim 923, wherein the one ormore heaters comprise natural distributed combustors.
 929. The method ofclaim 923, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 930. The method ofclaim 923, wherein the heat is controlled such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 931. The method of claim 923, wherein providing heat from theone or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 932. The method of claim 923, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 933.The method of claim 923, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 934. The method of claim 923, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 935. The method of claim 923, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 936. The method of claim 923, wherein the produced mixturecomprises non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons is less than about 0.15,and wherein the ratio of ethene to ethane is greater than about 0.001.937. The method of claim 923, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 938. The method of claim 923, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 939. The method of claim 923, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 940. The method of claim 923,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 941. The method of claim923, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 942. The method of claim 923,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 943. The methodof claim 923, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 944. The method of claim 923,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 945. The method of claim 923, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 946. The method of claim 923, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 947. The method of claim923, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 948. The method of claim 923,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 949. The method of claim 923,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 950. The method ofclaim 949, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 951. The method of claim 923, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 952. The method of claim 923, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 953. The method of claim 923, furthercomprising: providing H₂ to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 954. The method of claim 923, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 955. The method of claim 923, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 956. The methodof claim 923, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 957. The method of claim 923, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 958. Themethod of claim 923, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 959. The methodof claim 958, wherein at least about 20 heaters are disposed in theformation for each production well.
 960. The method of claim 923,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 961. The method of claim 923,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 962. A method of treating a hydrocarbon containingformation in situ, comprising: heating a portion of the formation to atemperature sufficient to support oxidation of hydrocarbons within theportion, wherein the portion is located substantially adjacent to awellbore; flowing an oxidant through a conduit positioned within thewellbore to a heater zone within the portion, wherein the heater zonesupports an oxidation reaction between hydrocarbons and the oxidant;reacting a portion of the oxidant with hydrocarbons to generate heat;and transferring generated heat substantially by conduction to apyrolysis zone of the formation to pyrolyze at least a portion of thehydrocarbons within the pyrolysis zone.
 963. The method of claim 962,wherein heating the portion of the formation comprises raising atemperature of the portion above about 400° C.
 964. The method of claim962, wherein the conduit comprises critical flow orifices, the methodfurther comprising flowing the oxidant through the critical floworifices to the heater zone.
 965. The method of claim 962, furthercomprising removing reaction products from the heater zone through thewellbore.
 966. The method of claim 962, further comprising removingexcess oxidant from the heater zone to inhibit transport of the oxidantto the pyrolysis zone.
 967. The method of claim 962, further comprisingtransporting the oxidant from the conduit to the heater zonesubstantially by diffusion.
 968. The method of claim 962, furthercomprising heating the conduit with reaction products being removedthrough the wellbore.
 969. The method of claim 962, wherein the oxidantcomprises hydrogen peroxide.
 970. The method of claim 962, wherein theoxidant comprises air.
 971. The method of claim 962, wherein the oxidantcomprises a fluid substantially free of nitrogen.
 972. The method ofclaim 962, further comprising limiting an amount of oxidant to maintaina temperature of the heater zone less than about 1200° C.
 973. Themethod of claim 962, wherein heating the portion of the formationcomprises electrically heating the formation.
 974. The method of claim962, wherein heating the portion of the formation comprises heating theportion using exhaust gases from a surface burner.
 975. The method ofclaim 962, wherein heating the portion of the formation comprisesheating the portion with a flameless distributed combustor.
 976. Themethod of claim 962, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 977. The method ofclaim 962, further comprising controlling the heat such that an averageheating rate of the pyrolysis zone is less than about 1° C. per dayduring pyrolysis.
 978. The method of claim 962, wherein heating theportion comprises heating the pyrolysis zone such that a thermalconductivity of at least a portion of the pyrolysis zone is greater thanabout 0.5 W/(m ° C.).
 979. The method of claim 962, further comprisingcontrolling a pressure within at least a majority of the pyrolysis zoneof the formation, wherein the controlled pressure is at least about 2.0bars absolute.
 980. The method of claim 962, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 981. The method of claim962, wherein transferring generated heat comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 982. The method of claim 962, wherein transferringgenerated heat comprises substantially uniformly increasing apermeability of a majority of the pyrolysis zone.
 983. The method ofclaim 962, wherein the heating is controlled to yield greater than about60% by weight of condensable hydrocarbons, as measured by the FischerAssay.
 984. The method of claim 962, wherein the wellbore is locatedalong strike to reduce pressure differentials along a heated length ofthe wellbore.
 985. The method of claim 962, wherein the wellbore islocated along strike to increase uniformity of heating along a heatedlength of the wellbore.
 986. The method of claim 962, wherein thewellbore is located along strike to increase control of heating along aheated length of the wellbore.
 987. A method of treating a hydrocarboncontaining formation in situ, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidant;flowing the oxidant into a conduit, and wherein the conduit is connectedsuch that the oxidant can flow from the conduit to the hydrocarbons;allowing the oxidant and the hydrocarbons to react to produce heat in aheater zone; allowing heat to transfer from the heater zone to apyrolysis zone in the formation to pyrolyze at least a portion of thehydrocarbons within the pyrolysis zone; and removing reaction productssuch that the reaction products are inhibited from flowing from theheater zone to the pyrolysis zone.
 988. The method of claim 987, whereinheating the portion of the formation comprises raising the temperatureof the portion above about 400° C.
 989. The method of claim 987, whereinheating the portion of the formation comprises electrically heating theformation.
 990. The method of claim 987, wherein heating the portion ofthe formation comprises heating the portion using exhaust gases from asurface burner.
 991. The method of claim 987, wherein the conduitcomprises critical flow orifices, the method further comprising flowingthe oxidant through the critical flow orifices to the heater zone. 992.The method of claim 987, wherein the conduit is located within awellbore, wherein removing reaction products comprises removing reactionproducts from the heater zone through the wellbore.
 993. The method ofclaim 987, further comprising removing excess oxidant from the heaterzone to inhibit transport of the oxidant to the pyrolysis zone.
 994. Themethod of claim 987, further comprising transporting the oxidant fromthe conduit to the heater zone substantially by diffusion.
 995. Themethod of claim 987, wherein the conduit is located within a wellbore,the method further comprising heating the conduit with reaction productsbeing removed through the wellbore to raise a temperature of the oxidantpassing through the conduit.
 996. The method of claim 987, wherein theoxidant comprises hydrogen peroxide.
 997. The method of claim 987,wherein the oxidant comprises air.
 998. The method of claim 987, whereinthe oxidant comprises a fluid substantially free of nitrogen.
 999. Themethod of claim 987, further comprising limiting an amount of oxidant tomaintain a temperature of the heater zone less than about 1200° C. 1000.The method of claim 987, further comprising limiting an amount ofoxidant to maintain a temperature of the heater zone at a temperaturethat inhibits production of oxides of nitrogen.
 1001. The method ofclaim 987, wherein heating a portion of the formation to a temperaturesufficient to support oxidation of hydrocarbons within the portionfurther comprises heating with a flameless distributed combustor. 1002.The method of claim 987, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1003. The method of claim 987, further comprising controlling the heatsuch that an average heating rate of the pyrolysis zone is less thanabout 1° C. per day during pyrolysis.
 1004. The method of claim 987,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 1005. The method of claim 987, whereinallowing heat to transfer comprises heating the pyrolysis zone such thata thermal conductivity of at least a portion of the pyrolysis zone isgreater than about 0.5 W/(m ° C.).
 1006. The method of claim 987,further comprising controlling a pressure within at least a majority ofthe pyrolysis zone, wherein the controlled pressure is at least about2.0 bars absolute.
 1007. The method of claim 987, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 1008. The method of claim987, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 1009. The method of claim 987, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the pyrolysis zone.
 1010. The method of claim 987,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1011. An in situ method for heating a hydrocarbon containing formation,comprising: heating a portion of the formation to a temperaturesufficient to support reaction of hydrocarbons within the portion of theformation with an oxidizing fluid, wherein the portion is locatedsubstantially adjacent to an opening in the formation; providing theoxidizing fluid to a heater zone in the formation; allowing theoxidizing gas to react with at least a portion of the hydrocarbons atthe heater zone to generate heat in the heater zone; and transferringthe generated heat substantially by conduction from the heater zone to apyrolysis zone in the formation.
 1012. The method of claim 1011, furthercomprising transporting the oxidizing fluid through the heater zone bydiffusion.
 1013. The method of claim 1011, further comprising directingat least a portion of the oxidizing fluid into the opening throughorifices of a conduit disposed in the opening.
 1014. The method of claim1011, further comprising controlling a flow of the oxidizing fluid withcritical flow orifices of a conduit disposed in the opening such that arate of oxidation is controlled.
 1015. The method of claim 1011, whereina conduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit.1016. The method of claim 1011, wherein a conduit is disposed within theopening, the method further comprising removing an oxidation productfrom the formation through the conduit and transferring substantial heatfrom the oxidation product in the conduit to the oxidizing fluid in theconduit.
 1017. The method of claim 1011, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit, wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 1018. The method of claim 1011,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 1019. The method of claim1011, wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 1020. The method of claim 1011, wherein the heater zoneextends radially from the opening a width of less than approximately0.15 m.
 1021. The method of claim 1011, wherein heating the portioncomprises applying electrical current to an electric heater disposedwithin the opening.
 1022. The method of claim 1011, wherein thepyrolysis zone is substantially adjacent to the heater zone.
 1023. Themethod of claim 1011, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1024. The method of claim 1011, further comprising controlling the heatsuch that an average heating rate of the pyrolysis zone is less thanabout 1° C. per day during pyrolysis.
 1025. The method of claim 1011,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 1026. The method of claim 1011, whereinallowing heat to transfer comprises heating the portion such that athermal conductivity of at least a portion of the pyrolysis zone isgreater than about 0.5 W/(m ° C.).
 1027. The method of claim 1011,further comprising controlling a pressure within at least a majority ofthe pyrolysis zone, wherein the controlled pressure is at least about2.0 bars absolute.
 1028. The method of claim 1011, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 1029. The method of claim1011, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 1030. The method of claim 1011, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the pyrolysis zone.
 1031. The method ofclaim 1011, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1032. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;producing a mixture from the formation; and maintaining an averagetemperature within the selected section above a minimum pyrolysistemperature and below a vaporization temperature of hydrocarbons havingcarbon numbers greater than 25 to inhibit production of a substantialamount of hydrocarbons having carbon numbers greater than 25 in themixture.
 1033. The method of claim 1032, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1034. The method of claim 1032,wherein maintaining the average temperature within the selected sectioncomprises maintaining the temperature within a pyrolysis temperaturerange.
 1035. The method of claim 1032, wherein the one or more heaterscomprise electrical heaters.
 1036. The method of claim 1032, wherein theone or more heaters comprise surface burners.
 1037. The method of claim1032, wherein the one or more heaters comprise flameless distributedcombustors.
 1038. The method of claim 1032, wherein the one or moreheaters comprise natural distributed combustors.
 1039. The method ofclaim 1032, wherein the minimum pyrolysis temperature is greater thanabout 270° C.
 1040. The method of claim 1032, wherein the vaporizationtemperature is less than approximately 450° C. at atmospheric pressure.1041. The method of claim 1032, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1042. The method of claim 1032, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1043. Themethod of claim 1032, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1044. The method of claim 1032, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1045.The method of claim 1032, wherein providing heat from the one or moreheaters comprises heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1046. The method of claim 1032, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1047. The method of claim 1032, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1048. The method of claim 1032, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1049. The method of claim 1032, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1050. The method of claim 1032, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1051. The method of claim 1032, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1052. The method of claim 1032,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1053. The method ofclaim 1032, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1054. Themethod of claim 1032, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1055. The method ofclaim 1032, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1056. The method of claim 1032, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1057. The methodof claim 1032, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1058. The method of claim1032, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1059. The method ofclaim 1032, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1060. The method of claim 1032, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1061.The method of claim 1032, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1062. The method of claim 1032, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1063. The method of claim 1062, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1064. The method of claim 1032, wherein controlling formation conditionscomprises recirculating a portion of hydrogen from the mixture into theformation.
 1065. The method of claim 1032, further comprising: providinghydrogen (H₂) to the heated section to hydrogenate hydrocarbons withinthe section; and heating a portion of the section with heat fromhydrogenation.
 1066. The method of claim 1032, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1067. Themethod of claim 1032, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1068. The method of claim 1032,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1069.The method of claim 1032, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1070. The method of claim 1032, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 1071. The method of claim 1070, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 1072. The method of claim 1032, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 1073. The method of claim 1032, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1074. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; controlling a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than 25; and producing a mixture from theformation.
 1075. The method of claim 1074, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 1076. The method of claim1074, wherein the one or more heaters comprise electrical heaters. 1077.The method of claim 1074, wherein the one or more heaters comprisesurface burners.
 1078. The method of claim 1074, wherein the one or moreheaters comprise flameless distributed combustors.
 1079. The method ofclaim 1074, wherein the one or more heaters comprise natural distributedcombustors.
 1080. The method of claim 1074, further comprisingcontrolling a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1081. The method of claim 1080, wherein controlling thetemperature comprises maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 1082. The method of claim1074, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1083. The method of claim 1074, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1084. The method of claim 1074, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1085. The method of claim 1074, wherein providing heat fromthe one or more heaters comprises heating the selected formation suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1086. The method of claim1074, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1087. The method of claim1074, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1088. The method of claim 1074,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1089. The method of claim1074, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1090. The methodof claim 1074, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1091.The method of claim 1074, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1092. The method of claim 1074, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1093. The method of claim 1074, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1094. The method of claim 1074, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1095. The method of claim 1074, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1096. The method of claim 1074, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1097. The method of claim 1074, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1098. The method of claim 1074, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1099. The method of claim 1074, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1100. The method of claim1074, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1101. The method of claim 1074,further comprising controlling the pressure within at least a majorityof the selected section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1102. The method of claim1074, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 1103. Themethod of claim 1102, wherein the partial pressure of H₂ is measuredwhen the mixture is at a production well.
 1104. The method of claim1074, wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 1105. Themethod of claim 1074, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 1106. Themethod of claim 1074, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 1107. The method of claim1074, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 1108. The method of claim 1074, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 1109. The method ofclaim 1074, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1110. The method of claim 1074, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heaters are disposed in the formation for eachproduction well.
 1111. The method of claim 1110, wherein at least about20 heaters are disposed in the formation for each production well. 1112.The method of claim 1074, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 1113.The method of claim 1074, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1114. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; and producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1115. The method of claim 1114, wherein theone or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 1116.The method of claim 1114, wherein the one or more heaters compriseelectrical heaters.
 1117. The method of claim 1114, wherein the one ormore heaters comprise surface burners.
 1118. The method of claim 1114,wherein the one or more heaters comprise flameless distributedcombustors.
 1119. The method of claim 1114, wherein the one or moreheaters comprise natural distributed combustors.
 1120. The method ofclaim 1114, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1121. The method ofclaim 1114, wherein controlling the temperature comprises maintainingthe temperature within the selected section within a pyrolysistemperature range.
 1122. The method of claim 1114, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1123. Themethod of claim 1114, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1124. The method of claim 1114, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1125.The method of claim 1114, wherein providing heat from the one or moreheaters comprises heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1126. The method of claim 1114, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1127. The method of claim 1114, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1128. The method of claim 1114, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1129. The method of claim 1114, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1130. The method of claim 1114, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1131. The method of claim 1114, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1132. The method of claim 1114,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1133. The method ofclaim 1114, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1134. Themethod of claim 1114, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1135. The method ofclaim 1114, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1136. The method of claim 1114, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1137. The methodof claim 1114, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1138. The method of claim1114, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1139. The method ofclaim 1114, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1140. The method of claim 1114, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1141.The method of claim 1114, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1142. The method of claim 1114, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1143. The method of claim 1142, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1144. The method of claim 1114, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1145. The methodof claim 1114, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1146. The method of claim 1114, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1147. The method of claim 1114, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1148. Themethod of claim 1114, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1149. The method of claim 1114,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1150.The method of claim 1114, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1151. The method of claim 1114, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 1152. The method of claim 1151, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 1153. The method of claim 1114, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 1154. The method of claim 1114, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1155. A methodof treating a hydrocarbon containing formation in situ, comprising:heating a section of the formation to a pyrolysis temperature from atleast a first heater, a second heater and a third heater, and whereinthe first heater, the second heater and the third heater are locatedalong a perimeter of the section; controlling heat input to the firstheater, the second heater and the third heater to limit a heating rateof the section to a rate configured to produce a mixture from theformation with an olefin content of less than about 15% by weight ofcondensable fluids (on a dry basis) within the produced mixture; andproducing the mixture from the formation through a production well.1156. The method of claim 1155, wherein superposition of heat form thefirst heater, second heater, and third heater pyrolyzes a portion of thehydrocarbons within the formation to fluids.
 1157. The method of claim1155, wherein the pyrolysis temperature is between about 270° C. andabout 400° C.
 1158. The method of claim 1155, wherein the first heateris operated for less than about twenty four hours a day.
 1159. Themethod of claim 1155, wherein the first heater comprises an electricalheater.
 1160. The method of claim 1155, wherein the first heatercomprises a surface burner.
 1161. The method of claim 1155, wherein thefirst heater comprises a flameless distributed combustor.
 1162. Themethod of claim 1155, wherein the first heater, second heater and thirdheater are positioned substantially at apexes of an equilateraltriangle.
 1163. The method of claim 1155, wherein the production well islocated substantially at a geometrical center of the first heater,second heater, and third heater.
 1164. The method of claim 1155, furthercomprising a fourth heater, fifth heater, and sixth heater located alongthe perimeter of the section.
 1165. The method of claim 1164, whereinthe heaters are located substantially at apexes of a regular hexagon.1166. The method of claim 1165, wherein the production well is locatedsubstantially at a center of the hexagon.
 1167. The method of claim1155, further comprising controlling a pressure and a temperature withinat least a majority of the section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 1168. The method of claim 1155,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1169. The method of claim 1155, further comprising controllingthe heat such that an average heating rate of the section is less thanabout 3° C. per day during pyrolysis.
 1170. The method of claim 1155,further comprising controlling the heat such that an average heatingrate of the section is less than about 1° C. per day during pyrolysis.1171. The method of claim 1155, wherein providing heat from the one ormore heaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1172. The method of claim 1155, wherein heating the section ofthe formation comprises transferring heat substantially by conduction.1173. The method of claim 1155, wherein providing heat from the one ormore heaters comprises heating the section such that a thermalconductivity of at least a portion of the section is greater than about0.5 W/(m ° C.).
 1174. The method of claim 1155, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 1175. The method of claim 1155, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 1176. The method of claim 1155, wherein the produced mixturecomprises non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons is less than about 0.15,and wherein the ratio of ethene to ethane is greater than about 0.001.1177. The method of claim 1155, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 1178. The method of claim 1155, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1179. The method of claim 1155, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1180. The method of claim 1155,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1181. The method of claim1155, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1182. The method of claim 1155,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1183. Themethod of claim 1155, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1184. The method of claim1155, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1185. The method of claim 1155, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1186. The method of claim 1155, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1187. The method of claim1155, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1188. The method of claim 1155,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1189. The method of claim 1155,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1190. The method ofclaim 1189, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1191. The method of claim 1155, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1192. The method of claim 1155, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1193. The method of claim1155, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1194. The method of claim1155, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1195. The method of claim 1155, wherein heating thesection comprises increasing a permeability of a majority of the sectionto greater than about 100 millidarcy.
 1196. The method of claim 1155,wherein heating the section comprises substantially uniformly increasinga permeability of a majority of the section.
 1197. The method of claim1155, further comprising controlling the heat to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1198. The method of claim 1155, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heaters are disposed in the formation for eachproduction well.
 1199. The method of claim 1198, wherein at least about20 heaters are disposed in the formation for each production well. 1200.The method of claim 1155, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 1201.The method of claim 1155, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1202. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; and producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1203. The method ofclaim 1202, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 1204. The method of claim 1202, wherein the one or moreheaters comprise electrical heaters.
 1205. The method of claim 1202,wherein the one or more heaters comprise surface burners.
 1206. Themethod of claim 1202, wherein the one or more heaters comprise flamelessdistributed combustors.
 1207. The method of claim 1202, wherein the oneor more heaters comprise natural distributed combustors.
 1208. Themethod of claim 1202, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1209. The method of claim 1208, wherein controlling the temperaturecomprises maintaining the temperature within the selected section withina pyrolysis temperature range.
 1210. The method of claim 1202, furthercomprising controlling the heat such that an average heating rate of theselected section is less than about 1° C. per day during pyrolysis.1211. The method of claim 1202, wherein providing heat from the one ormore heaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1212. The method of claim 1202, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1213.The method of claim 1202, wherein providing heat from the one or moreheaters comprises, heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1214. The method of claim 1202, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1215. The method of claim 1202, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1216. The method of claim 1202, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1217. The method of claim 1202, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1218. The method of claim 1202, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1219. The method of claim 1202, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1220. The method of claim 1202,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1221. The method of claim1202, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1222. The method of claim 1202,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1223. Themethod of claim 1202, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1224. The method of claim1202, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1225. The method of claim 1202, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1226. The method of claim 1202, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1227. The method of claim1202, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1228. The method of claim 1202,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 1229. The method of claim 1202,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1230. The method ofclaim 1229, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1231. The method of claim 1202, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1232. The method of claim 1202, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1233. The method of claim1202, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1234. The method of claim1202, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1235. The method of claim 1202, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1236. Themethod of claim 1202, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1237. The method of claim 1202, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1238. Themethod of claim 1202, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1239. The methodof claim 1238, wherein at least about 20 heaters are disposed in theformation for each production well.
 1240. The method of claim 1202,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1241. The method of claim 1202,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1242. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1243. The method of claim 1242, wherein the oneor more heaters comprise at least two heaters, and wherein superpositionof heat from at least the two heaters pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1244. Themethod of claim 1242, wherein the one or more heaters compriseelectrical heaters.
 1245. The method of claim 1242, wherein the one ormore heaters comprise surface burners.
 1246. The method of claim 1242,wherein the one or more heaters comprise flameless distributedcombustors.
 1247. The method of claim 1242, wherein the one or moreheaters comprise natural distributed combustors.
 1248. The method ofclaim 1242, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1249. The method ofclaim 1248, wherein controlling the temperature comprises maintainingthe temperature within the selected section within a pyrolysistemperature range.
 1250. The method of claim 1242, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1251. Themethod of claim 1242, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1252. The method of claim 1242, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1253.The method of claim 1242, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1254. The method of claim 1242, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1255. The method of claim 1242, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1256. The method of claim 1242, wherein theproduced mixture comprises non-condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the non-condensablehydrocarbons are olefins.
 1257. The method of claim 1242, wherein theproduced mixture comprises non-condensable hydrocarbons, wherein a molarratio of ethene to ethane in the non-condensable hydrocarbons is lessthan about 0.15, and wherein the ratio of ethene to ethane is greaterthan about 0.001.
 1258. The method of claim 1242, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1259. The method of claim 1242, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1260. The method of claim 1242,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1261. The method ofclaim 1242, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1262. Themethod of claim 1242, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1263. The method ofclaim 1242, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1264. The method of claim 1242, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1265. The methodof claim 1242, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1266. The method of claim1242, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1267. The method ofclaim 1242, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1268. The method of claim 1242, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1269.The method of claim 1242, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1270. The method of claim 1242, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1271. The method of claim 1270, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1272. The method of claim 1242, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1273. The methodof claim 1242, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1274. The method of claim 1242, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1275. The method of claim 1242, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1276. Themethod of claim 1242, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1277. The method of claim 1242,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1278.The method of claim 1242, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1279. The method of claim 1242, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 1280. The method of claim 1279, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 1281. The method of claim 1242, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 1282. The method of claim 1242, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1283. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; and producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1284. Themethod of claim 1283, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1285. The method of claim 1283, wherein the one ormore heaters comprise electrical heaters.
 1286. The method of claim1283, wherein the one or more heaters comprise surface burners. 1287.The method of claim 1283, wherein the one or more heaters compriseflameless distributed combustors.
 1288. The method of claim 1283,wherein the one or more heaters comprise natural distributed combustors.1289. The method of claim 1283, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1290. The method of claim 1289, wherein controlling thetemperature comprises maintaining the temperature within the selectedsection within a pyrolysis temperature range.
 1291. The method of claim1283, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1292. The method of claim 1283, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1293. The method of claim 1283, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1294. The method of claim 1283, wherein providing heat fromthe one or more heaters comprises heating the selected formation suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1295. The method of claim1283, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1296. The method of claim1283, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1297. The method of claim 1283,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1298. The method of claim1283, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1299. The methodof claim 1283, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1300.The method of claim 1283, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1301. The method of claim 1283, wherein the produced mixturecomprises condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.1302. The method of claim 1283, wherein the produced mixture comprisescondensable hydrocarbons, and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1303. The methodof claim 1283, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1304. The method of claim 1283, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1305. The methodof claim 1283, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1306. The method of claim1283, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1307. The method ofclaim 1283, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1308. The method of claim 1283, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1309.The method of claim 1283, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1310. The method of claim 1283, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bars.
 1311. The method of claim 1310, wherein the partialpressure of H₂ is measured when the mixture is at a production well.1312. The method of claim 1283, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1313. The methodof claim 1283, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1314. The method of claim 1283, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1315. The method of claim 1283, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1316. Themethod of claim 1283, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1317. The method of claim 1283,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1318.The method of claim 1283, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1319. The method of claim 1283, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 1320. The method of claim 1319, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 1321. The method of claim 1283, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 1322. The method of claim 1283, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1323. A methodof treating a hydrocarbon containing formation in situ, comprising:raising a temperature of a first section of the formation with one ormore heaters to a first pyrolysis temperature; heating the first sectionto an upper pyrolysis temperature, wherein heat is supplied to the firstsection at a rate configured to inhibit olefin production; producing afirst mixture from the formation, wherein the first mixture comprisescondensable hydrocarbons and H₂; creating a second mixture from thefirst mixture, wherein the second mixture comprises a higherconcentration of H₂ than the first mixture; raising a temperature of asecond section of the formation with one or more heaters to a secondpyrolysis temperature; providing a portion of the second mixture to thesecond section; heating the second section to an upper pyrolysistemperature, wherein heat is supplied to the second section at a rateconfigured to inhibit olefin production; and producing a third mixturefrom the second section.
 1324. The method of claim 1323, whereincreating the second mixture comprises removing condensable hydrocarbonsfrom the first mixture.
 1325. The method of claim 1323, wherein creatingthe second mixture comprises removing water from the first mixture.1326. The method of claim 1323, wherein creating the second mixturecomprises removing carbon dioxide from the first mixture.
 1327. Themethod of claim 1323, wherein the first pyrolysis temperature is greaterthan about 270° C.
 1328. The method of claim 1323, wherein the secondpyrolysis temperature is greater than about 270° C.
 1329. The method ofclaim 1323, wherein the upper pyrolysis temperature is about 500° C.1330. The method of claim 1323, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters pyrolyzes at least some hydrocarbons within the first orsecond selected section of the formation.
 1331. The method of claim1323, wherein the one or more heaters comprise electrical heaters. 1332.The method of claim 1323, wherein the one or more heaters comprisesurface burners.
 1333. The method of claim 1323, wherein the one or moreheaters comprise flameless distributed combustors.
 1334. The method ofclaim 1323, wherein the one or more heaters comprise natural distributedcombustors.
 1335. The method of claim 1323, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe first section and the second section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 1336. The method of claim 1323,further comprising controlling the heat to the first and second sectionssuch that an average heating rate of the first and second sections isless than about 1° C. per day during pyrolysis.
 1337. The method ofclaim 1323, wherein heating the first and the second sections comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1338. The method of claim 1323, wherein heating the first andsecond sections comprises transferring heat substantially by conduction.1339. The method of claim 1323, wherein heating the first and secondsections comprises heating the first and second sections such that athermal conductivity of at least a portion of the first and secondsections is greater than about 0.5 W/(m ° C.).
 1340. The method of claim1323, wherein the first or third mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1341. Themethod of claim 1323, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 1342. The methodof claim 1323, wherein the first or third mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1343. The method of claim 1323, wherein the first or thirdmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1344. The method of claim 1323, wherein thefirst or third mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1345. The method of claim 1323,wherein the first or third mixture comprises condensable hydrocarbons,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1346. The method ofclaim 1323, wherein the first or third mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1347. Themethod of claim 1323, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1348. The methodof claim 1323, wherein the first or third mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1349. The method of claim 1323, wherein the first or thirdmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 1350.The method of claim 1323, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 1351. Themethod of claim 1323, wherein the first or third mixture comprisesnon-condensable component, and wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 1352.The method of claim 1323, wherein the first or third mixture comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 1353. The method of claim 1323, wherein the first orthird mixture comprises ammonia, and wherein the ammonia is used toproduce fertilizer.
 1354. The method of claim 1323, further comprisingcontrolling a pressure within at least a majority of the first or secondsections of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 1355. The method of claim 1323, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂ withinthe mixture is greater than about 0.5 bars.
 1356. The method of claim1355, wherein the partial pressure of H₂ within a mixture is measuredwhen the mixture is at a production well.
 1357. The method of claim1323, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1358. The method of claim 1323, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section; and heatinga portion of the first or second section with heat from hydrogenation.1359. The method of claim 1323, further comprising: producing hydrogenand condensable hydrocarbons from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 1360. The method of claim 1323, furthercomprising increasing a permeability of a majority of the first orsecond section to greater than about 100 millidarcy.
 1361. The method ofclaim 1323, further comprising substantially uniformly increasing apermeability of a majority of the first or second section.
 1362. Themethod of claim 1323, wherein the heating is controlled to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1363. The method of claim 1323, wherein producing thefirst or third mixture comprises producing the first or third mixture ina production well, and wherein at least about 7 heaters are disposed inthe formation for each production well.
 1364. The method of claim 1363,wherein at least about 20 heaters are disposed in the formation for eachproduction well.
 1365. The method of claim 1323, further comprisingproviding heat from three or more heaters to at least a portion of theformation, wherein three or more of the heaters are located in theformation in a unit of heaters, and wherein the unit of heaterscomprises a triangular pattern.
 1366. The method of claim 1323, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1367. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;producing a mixture from the formation; and hydrogenating a portion ofthe produced mixture with H₂ produced from the formation.
 1368. Themethod of claim 1367, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1369. The method of claim 1367, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1370. The method of claim 1367, wherein the one ormore heaters comprise electrical heaters.
 1371. The method of claim1367, wherein the one or more heaters comprise surface burners. 1372.The method of claim 1367, wherein the one or more heaters compriseflameless distributed combustors.
 1373. The method of claim 1367,wherein the one or more heaters comprise natural distributed combustors.1374. The method of claim 1367, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1375. The method of claim 1367, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1376. Themethod of claim 1367, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1377. The method of claim 1367, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1378.The method of claim 1367, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1379. The method of claim 1367, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1380. The method of claim 1367, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1381. The method of claim 1367, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1382. The method of claim 1367,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1383. The method ofclaim 1367, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1384. Themethod of claim 1367, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1385. Themethod of claim 1367, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1386. Themethod of claim 1367, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1387. The method ofclaim 1367, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1388. The method of claim 1367, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1389. The methodof claim 1367, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1390. The method of claim1367, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1391. The method ofclaim 1367, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1392. The method of claim 1367, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1393.The method of claim 1367, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1394. The method of claim 1367, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1395. The method ofclaim 1367, wherein a partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1396. The method ofclaim 1367, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1397. The method of claim 1367, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1398. The method of claim 1367, whereinallowing the heat to transfer comprises increasing a permeability of amajority of the selected section to greater than about 100 millidarcy.1399. The method of claim 1367, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1400. The method of claim 1367,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1401. The method of claim 1367, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 1402.The method of claim 1401, wherein at least about 20 heaters are disposedin the formation for each production well.
 1403. The method of claim1367, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 1404. The method of claim1367, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1405. A method of treating a hydrocarbon containingformation in situ, comprising: heating a first section of the formation;producing H₂ from the first section of formation; heating a secondsection of the formation; and recirculating a portion of the H₂ from thefirst section into the second section of the formation to provide areducing environment within the second section of the formation. 1406.The method of claim 1405, wherein heating the first section or heatingthe second section comprises heating with an electrical heater. 1407.The method of claim 1405, wherein heating the first section or heatingthe second section comprises heating with a surface burner.
 1408. Themethod of claim 1405, wherein heating the first section or heating thesecond section comprises heating with a flameless distributed combustor.1409. The method of claim 1405, wherein heating the first section orheating the second section comprises heating with a natural distributedcombustor.
 1410. The method of claim 1405, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe first or second section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1411. The method of claim 1405,further comprising controlling the heat such that an average heatingrate of the first or second section is less than about 1° C. per dayduring pyrolysis.
 1412. The method of claim 1405, wherein heating thefirst section or heating the second section further comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1413. The method of claim 1405, wherein heating the firstsection or heating the second section comprises transferring heatsubstantially by conduction.
 1414. The method of claim 1405, whereinheating the first section or heating the second section comprisesheating the formation such that a thermal conductivity of at least aportion of the first or second section is greater than about 0.5 W/(m °C.).
 1415. The method of claim 1405, further comprising producing amixture from the second section, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.1416. The method of claim 1405, further comprising producing a mixturefrom the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 1417. The methodof claim 1405, further comprising producing a mixture from the secondsection, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.1418. The method of claim 1405, further comprising producing a mixturefrom the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 1419. The method of claim 1405, further comprising producing amixture from the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1420. The method of claim 1405, further comprising producing amixture from the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 1421. The method of claim 1405, further comprising producing amixture from the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.1422. The method of claim 1405, further comprising producing a mixturefrom the second section, wherein the produced mixture comprisescondensable hydrocarbons, and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1423. The methodof claim 1405, further comprising producing a mixture from the secondsection, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1424. The method of claim 1405, further comprising producinga mixture from the second section, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1425. The methodof claim 1405, further comprising producing a mixture from the secondsection, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1426. The method of claim1405, further comprising producing a mixture from the second section,wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1427. The method of claim 1405, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1428. The method of claim1405, further comprising producing a mixture from the second section,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 1429. The method of claim 1405, furthercomprising controlling a pressure within at least a majority of thefirst or second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1430. The method of claim1405, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 1431. Themethod of claim 1430, wherein the partial pressure of H₂ within amixture is measured when the mixture is at a production well.
 1432. Themethod of claim 1405, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 1433. The method of claim1405, further comprising: providing hydrogen (H₂) to the second sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe second section with heat from hydrogenation.
 1434. The method ofclaim 1405, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1435. The method of claim 1405, wherein heating thefirst section or heating the second section comprises increasing apermeability of a majority of the first or second section, respectively,to greater than about 100 millidarcy.
 1436. The method of claim 1405,wherein heating the first section or heating the second sectioncomprises substantially uniformly increasing a permeability of amajority of the first or second section, respectively.
 1437. The methodof claim 1405, further comprising controlling the heating of the firstsection or controlling the heat of the second section to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1438. The method of claim 1405, further comprisingproducing a mixture from the formation in a production well, and whereinat least about 7 heaters are disposed in the formation for eachproduction well.
 1439. The method of claim 1438, wherein at least about20 heaters are disposed in the formation for each production well. 1440.The method of claim 1405, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 1441.The method of claim 1405, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1442. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation; producing a mixture from the formation; andcontrolling formation conditions such that the mixture produced from theformation comprises condensable hydrocarbons including H₂, wherein thepartial pressure of H₂ within the mixture is greater than about 0.5bars.
 1443. The method of claim 1442, wherein the one or more heaterscomprise at least two heaters, and wherein superposition of heat from atleast the two heaters pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1444. The method of claim 1442,wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1445. The method of claim 1442, wherein the one or more heaterscomprise electrical heaters.
 1446. The method of claim 1442, wherein theone or more heaters comprise surface burners.
 1447. The method of claim1442, wherein the one or more heaters comprise flameless distributedcombustors.
 1448. The method of claim 1442, wherein the one or moreheaters comprise natural distributed combustors.
 1449. The method ofclaim 1442, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1450. The method ofclaim 1442, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1451. The method of claim 1442, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1452. The method of claim 1442, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1453. The method of claim 1442, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 1454. The method of claim 1442,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1455. The method of claim 1442,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1456. The method of claim 1442, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1457. The method of claim 1442,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1458. The method ofclaim 1442, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1459. Themethod of claim 1442, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1460. Themethod of claim 1442, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1461. Themethod of claim 1442, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1462. The method ofclaim 1442, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1463. The method of claim 1442, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1464. The methodof claim 1442, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1465. The method of claim1442, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1466. The method ofclaim 1442, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1467. The method of claim 1442, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1468.The method of claim 1442, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1469. The method of claim 1442, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1470. The methodof claim 1442, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.1471. The method of claim 1442, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 1472. The method of claim 1442, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 1473. The method of claim1442, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 1474. The method of claim 1442, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 1475. The method ofclaim 1442, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1476. The method of claim 1442, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heaters are disposed in the formation for eachproduction well.
 1477. The method of claim 1442, further comprisingproviding heat from three or more heaters to at least a portion of theformation, wherein three or more of the heaters are located in theformation in a unit of heaters, and wherein the unit of heaterscomprises a triangular pattern.
 1478. The method of claim 1442, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1479. The method of claim 1442, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1480. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;maintaining a pressure of the selected section above atmosphericpressure to increase a partial pressure of H₂, as compared to thepartial pressure of H₂ at atmospheric pressure, in at least a majorityof the selected section; and producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1481. The method of claim 1480,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1482. The method of claim 1480, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1483. The method of claim 1480, wherein the one or more heaterscomprise electrical heaters.
 1484. The method of claim 1480, wherein theone or more heaters comprise surface burners.
 1485. The method of claim1480, wherein the one or more heaters comprise flameless distributedcombustors.
 1486. The method of claim 1480, wherein the one or moreheaters comprise natural distributed combustors.
 1487. The method ofclaim 1480, further comprising controlling the pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1488. The method of claim 1480, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1489. The method of claim 1480,wherein providing heat from the one or more heaters to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 1490. The method of claim 1480,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 1491. The method of claim 1480, whereinproviding heat from the one or more heaters comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 1492. Themethod of claim 1480, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1493. The method of claim1480, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.1494. The method of claim 1480, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 1495. The method of claim 1480, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1496. The method of claim 1480, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1497. The method of claim 1480,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1498. The method of claim1480, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1499. The method of claim 1480,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1500. Themethod of claim 1480, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1501. The method of claim1480, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1502. The method of claim 1480, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1503. The method of claim 1480, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1504. The method of claim1480, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1505. The method of claim 1480,further comprising controlling the pressure within at least a majorityof the selected section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 1506. The method of claim1480, further comprising increasing the pressure of the selectedsection, to an upper limit of about 21 bars absolute, to increase anamount of non-condensable hydrocarbons produced from the formation.1507. The method of claim 1480, further comprising decreasing pressureof the selected section, to a lower limit of about atmospheric pressure,to increase an amount of condensable hydrocarbons produced from theformation.
 1508. The method of claim 1480, wherein the partial pressurecomprises a partial pressure based on properties measured at aproduction well.
 1509. The method of claim 1480, further comprisingaltering the pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1510. The method of claim 1480, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1511. The method of claim 1480, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1512. The method of claim 1480, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1513. Themethod of claim 1480, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1514. The method of claim 1480,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1515.The method of claim 1480, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1516. The method of claim 1480, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 1517. The method of claim 1516, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 1518. The method of claim 1480, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 1519. The method of claim 1480, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1520. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; providing H₂ to the formation toproduce a reducing environment in at least some of the formation;producing a mixture from the formation.
 1521. The method of claim 1520,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1522. The method of claim 1520, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1523. The method of claim 1520, further comprising separating aportion of hydrogen within the mixture and recirculating the portioninto the formation.
 1524. The method of claim 1520, wherein the one ormore heaters comprise electrical heaters.
 1525. The method of claim1520, wherein the one or more heaters comprise surface burners. 1526.The method of claim 1520, wherein the one or more heaters compriseflameless distributed combustors.
 1527. The method of claim 1520,wherein the one or more heaters comprise natural distributed combustors.1528. The method of claim 1520, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1529. The method of claim 1520, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1530. Themethod of claim 1520, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1531. The method of claim 1520, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1532.The method of claim 1520, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1533. The method of claim 1520, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1534. The method of claim 1520, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1535. The method of claim 1520, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1536. The method of claim 1520,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1537. The method ofclaim 1520, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1538. Themethod of claim 1520, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1539. Themethod of claim 1520, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1540. Themethod of claim 1520, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1541. The method ofclaim 1520, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1542. The method of claim 1520, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1543. The methodof claim 1520, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1544. The method of claim1520, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1545. The method ofclaim 1520, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1546. The method of claim 1520, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1547.The method of claim 1520, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1548. The method of claim 1520, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1549. The method ofclaim 1520, wherein a partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1550. The method ofclaim 1520, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1551. The method of claim 1520, whereinproviding hydrogen (H₂) to the formation further comprises:hydrogenating hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1552. The method of claim1520, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1553. The method of claim 1520, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1554. Themethod of claim 1520, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1555. The method of claim 1520, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1556. Themethod of claim 1520, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1557. The methodof claim 1556, wherein at least about 20 heaters are disposed in theformation for each production well.
 1558. The method of claim 1520,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1559. The method of claim 1520,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1560. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;providing H₂ to the selected section to hydrogenate hydrocarbons withinthe selected section and to heat a portion of the section with heat fromthe hydrogenation; and controlling heating of the selected section bycontrolling amounts of H₂ provided to the selected section.
 1561. Themethod of claim 1560, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1562. The method of claim 1560, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1563. The method of claim 1560, wherein the one ormore heaters comprise electrical heaters.
 1564. The method of claim1560, wherein the one or more heaters comprise surface burners. 1565.The method of claim 1560, wherein the one or more heaters compriseflameless distributed combustors.
 1566. The method of claim 1560,wherein the one or more heaters comprise natural distributed combustors.1567. The method of claim 1560, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1568. The method of claim 1560, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1569. Themethod of claim 1560, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1570. The method of claim 1560, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1571.The method of claim 1560, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1572. The method of claim 1560, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 1573. The method of claim 1560, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1574.The method of claim 1560, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.1575. The method of claim 1560, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1576.The method of claim 1560, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1577. Themethod of claim 1560, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1578. Themethod of claim 1560, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1579. Themethod of claim 1560, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1580. The method ofclaim 1560, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1581. Themethod of claim 1560, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1582. The method of claim1560, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1583. The method of claim 1560, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1584. The method of claim 1560, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 1585. The method of claim1560, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 1586. The method of claim 1560, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 1587. The method of claim 1560, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 1588. The method of claim 1587, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 1589. The method of claim 1560, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1590. The method of claim 1560, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from a produced mixture into the formation.
 1591. The methodof claim 1560, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1592. The method of claim 1560, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1593. Themethod of claim 1560, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1594. The method of claim 1560, further comprisingproducing a mixture in a production well, wherein at least about 7heaters are disposed in the formation for each production well. 1595.The method of claim 1594, wherein at least about 20 heaters are disposedin the formation for each production well.
 1596. The method of claim1560, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 1597. The method of claim1560, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1598. An in situ method for producing H₂ from ahydrocarbon containing formation, comprising: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from the one or more heaters to a selected section of theformation; and producing a mixture from the formation, wherein a H₂partial pressure within the mixture is greater than about 0.5 bars.1599. The method of claim 1598, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 1600. The method of claim 1598, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 1601. The method of claim 1598, whereinthe one or more heaters comprise electrical heaters.
 1602. The method ofclaim 1598, wherein the one or more heaters comprise surface burners.1603. The method of claim 1598, wherein the one or more heaters compriseflameless distributed combustors.
 1604. The method of claim 1598,wherein the one or more heaters comprise natural distributed combustors.1605. The method of claim 1598, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1606. The method of claim 1598, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1607. Themethod of claim 1598, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1608. The method of claim 1598, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1609.The method of claim 1598, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1610. The method of claim 1598, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1611. The method of claim 1598, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1612. The method of claim 1598, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1613. The method of claim 1598,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1614. The method ofclaim 1598, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1615. Themethod of claim 1598, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1616. Themethod of claim 1598, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1617. Themethod of claim 1598, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1618. The method ofclaim 1598, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1619. The method of claim 1598, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1620. The methodof claim 1598, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1621. The method of claim1598, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1622. The method ofclaim 1598, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1623. The method of claim 1598, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1624.The method of claim 1598, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1625. The method of claim 1598, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 1626. The methodof claim 1598, further comprising recirculating a portion of thehydrogen within the mixture into the formation.
 1627. The method ofclaim 1598, further comprising condensing a hydrocarbon component fromthe produced mixture and hydrogenating the condensed hydrocarbons with aportion of the hydrogen.
 1628. The method of claim 1598, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1629. The method of claim 1598, whereinallowing the heat to transfer comprises increasing a permeability of amajority of the selected section to greater than about 100 millidarcy.1630. The method of claim 1598, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1631. The method of claim 1598,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1632. The method of claim 1598, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 1633.The method of claim 1632, wherein at least about 20 heaters are disposedin the formation for each production well.
 1634. The method of claim1598, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 1635. The method of claim1598, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1636. The method of claim 1598, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1637. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using anatomic hydrogen weight percentage of at least a portion of hydrocarbonsin the selected section, and wherein at least the portion of thehydrocarbons in the selected section comprises an atomic hydrogen weightpercentage, when measured on a dry, ash-free basis, of greater thanabout 4.0%; and producing a mixture from the formation.
 1638. The methodof claim 1637, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 1639. The method of claim 1637, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1640. The method of claim 1637, wherein the one ormore heaters comprise electrical heaters.
 1641. The method of claim1637, wherein the one or more heaters comprise surface burners. 1642.The method of claim 1637, wherein the one or more heaters compriseflameless distributed combustors.
 1643. The method of claim 1637,wherein the one or more heaters comprise natural distributed combustors.1644. The method of claim 1637, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1645. The method of claim 1637, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1646. Themethod of claim 1637, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1647. The method of claim 1637, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1648.The method of claim 1637, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1649. The method of claim 1637, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1650. The method of claim 1637, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1651. The method of claim 1637, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1652. The method of claim 1637,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1653. The method ofclaim 1637, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1654. Themethod of claim 1637, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1655. Themethod of claim 1637, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1656. Themethod of claim 1637, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1657. The method ofclaim 1637, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1658. The method of claim 1637, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1659. The methodof claim 1637, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1660. The method of claim1637, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1661. The method ofclaim 1637, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1662. The method of claim 1637, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1663.The method of claim 1637, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1664. The method of claim 1637, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1665. The method ofclaim 1664, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1666. The method ofclaim 1637, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1667. The method of claim 1637, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1668. The method ofclaim 1637, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1669. The method ofclaim 1637, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1670. The method of claim 1637, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1671. Themethod of claim 1637, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1672. The method of claim 1637, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1673. Themethod of claim 1637, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1674. The methodof claim 1673, wherein at least about 20 heaters are disposed in theformation for each production well.
 1675. The method of claim 1637,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1676. The method of claim 1637,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1677. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein at least some hydrocarbons within the selected section have aninitial atomic hydrogen weight percentage of greater than about 4.0%;and producing a mixture from the formation.
 1678. The method of claim1677, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1679. The method of claim 1677, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1680. The method of claim 1677, wherein the one or more heaterscomprise electrical heaters.
 1681. The method of claim 1677, wherein theone or more heaters comprise surface burners.
 1682. The method of claim1677, wherein the one or more heaters comprise flameless distributedcombustors.
 1683. The method of claim 1677, wherein the one or moreheaters comprise natural distributed combustors.
 1684. The method ofclaim 1677, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1685. The method ofclaim 1677, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1686. The method of claim 1677, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1687. The method of claim 1677, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1688. The method of claim 1677, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 1689. The method of claim 1677,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1690. The method of claim 1677,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1691. The method of claim 1677, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1692. The method of claim 1677,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1693. The method ofclaim 1677, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1694. Themethod of claim 1677, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1695. Themethod of claim 1677, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1696. Themethod of claim 1677, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1697. The method ofclaim 1677, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1698. The method of claim 1677, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1699. The methodof claim 1677, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1700. The method of claim1677, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1701. The method ofclaim 1677, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1702. The method of claim 1677, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1703.The method of claim 1677, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1704. The method of claim 1677, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1705. The method ofclaim 1704, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1706. The method ofclaim 1677, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1707. The method of claim 1677, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1708. The method ofclaim 1677, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1709. The method ofclaim 1677, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1710. The method of claim 1677, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1711. Themethod of claim 1677, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1712. The method of claim 1677, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1713. Themethod of claim 1677, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1714. The methodof claim 1713, wherein at least about 20 heaters are disposed in theformation for each production well.
 1715. The method of claim 1677,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern. 1716 The method of claim 1677,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1717. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating usingvitrinite reflectance of at least some hydrocarbons in the selectedsection, and wherein at least a portion of the hydrocarbons in theselected section comprises a vitrinite reflectance of greater than about0.3%; wherein at least a portion of the hydrocarbons in the selectedsection comprises a vitrinite reflectance of less than about 4.5%; andproducing a mixture from the formation.
 1718. The method of claim 1717,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1719. The method of claim 1717, further comprising maintaining atemperature within the selected section within a pyrolysis temperature.1720. The method of claim 1717, wherein the vitrinite reflectance of atleast the portion of hydrocarbons within the selected section is betweenabout 0.47% and about 1.5% such that a majority of the produced mixturecomprises condensable hydrocarbons.
 1721. The method of claim 1717,wherein the vitrinite reflectance of at least the portion ofhydrocarbons within the selected section is between about 1.4% and about4.2% such that a majority of the produced mixture comprisesnon-condensable hydrocarbons.
 1722. The method of claim 1717, whereinthe one or more heaters comprise electrical heaters.
 1723. The method ofclaim 1717, wherein the one or more heaters comprise surface burners.1724. The method of claim 1717, wherein the one or more heaters compriseflameless distributed combustors.
 1725. The method of claim 1717,wherein the one or more heaters comprise natural distributed combustors.1726. The method of claim 1717, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1727. The method of claim 1717, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1728. Themethod of claim 1717, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1729. The method of claim 1717, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1730.The method of claim 1717, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1731. The method of claim 1717, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1732. The method of claim 1717, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1733. The method of claim 1717, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1734. The method of claim 1717,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1735. The method ofclaim 1717, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1736. Themethod of claim 1717, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1737. Themethod of claim 1717, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1738. Themethod of claim 1717, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1739. The method ofclaim 1717, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1740. The method of claim 1717, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1741. The methodof claim 1717, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1742. The method of claim1717, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1743. The method ofclaim 1717, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1744. The method of claim 1717, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1745.The method of claim 1717, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1746. The method of claim 1717, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1747. The method ofclaim 1746, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1748. The method ofclaim 1717, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1749. The method of claim 1717, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1750. The method ofclaim 1717, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1751. The method ofclaim 1717, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1752. The method of claim 1717, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1753. Themethod of claim 1717, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1754. The method of claim 1717, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1755. Themethod of claim 1717, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1756. The methodof claim 1755, wherein at least about 20 heaters are disposed in theformation for each production well.
 1757. The method of claim 1717,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1758. The method of claim 1717,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1759. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using a totalorganic matter weight percentage of at least a portion of the selectedsection, and wherein at least the portion of the selected sectioncomprises a total organic matter weight percentage, of at least about5.0%; and producing a mixture from the formation.
 1760. The method ofclaim 1759, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 1761. The method of claim 1759, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1762. The method of claim 1759, wherein the one ormore heaters comprise electrical heaters.
 1763. The method of claim1759, wherein the one or more heaters comprise surface burners. 1764.The method of claim 1759, wherein the one or more heaters compriseflameless distributed combustors.
 1765. The method of claim 1759,wherein the one or more heaters comprise natural distributed combustors.1766. The method of claim 1759, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1767. The method of claim 1759, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1768. Themethod of claim 1759, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1769. The method of claim 1759, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1770.The method of claim 1759, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1771. The method of claim 1759, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1772. The method of claim 1759, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1773. The method of claim 1759, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1774. The method of claim 1759,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1775. The method ofclaim 1759, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1776. Themethod of claim 1759, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1777. Themethod of claim 1759, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1778. Themethod of claim 1759, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1779. The method ofclaim 1759, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1780. The method of claim 1759, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1781. The methodof claim 1759, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1782. The method of claim1759, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1783. The method ofclaim 1759, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1784. The method of claim 1759, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1785.The method of claim 1759, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1786. The method of claim 1759, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1787. The method ofclaim 1786, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1788. The method ofclaim 1759, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1789. The method of claim 1759, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1790. The method ofclaim 1759, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1791. The method ofclaim 1759, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1792. The method of claim 1759, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1793. Themethod of claim 1759, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1794. The method of claim 1759, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1795. Themethod of claim 1759, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1796. The methodof claim 1795, wherein at least about 20 heaters are disposed in theformation for each production well.
 1797. The method of claim 1759,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1798. The method of claim 1759,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1799. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein at least some hydrocarbons within the selected section have aninitial total organic matter weight percentage of at least about 5.0%;and producing a mixture from the formation.
 1800. The method of claim1799, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1801. The method of claim 1799, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1802. The method of claim 1799, wherein the one or more heaterscomprise electrical heaters.
 1803. The method of claim 1799, wherein theone or more heaters comprise surface burners.
 1804. The method of claim1799, wherein the one or more heaters comprise flameless distributedcombustors.
 1805. The method of claim 1799, wherein the one or moreheaters comprise natural distributed combustors.
 1806. The method ofclaim 1799, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1807. The method ofclaim 1799, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1808. The method of claim 1799, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1809. The method of claim 1799, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1810. The method of claim 1799, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 1811. The method of claim 1799,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1812. The method of claim 1799,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1813. The method of claim 1799, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1814. The method of claim 1799,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1815. The method ofclaim 1799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1816. Themethod of claim 1799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1817. Themethod of claim 1799, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1818. Themethod of claim 1799, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1819. The method ofclaim 1799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1820. The method of claim 1799, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1821. The methodof claim 1799, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1822. The method of claim1799, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1823. The method ofclaim 1799, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1824. The method of claim 1799, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1825.The method of claim 1799, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1826. The method of claim 1799, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1827. The method ofclaim 1826, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1828. The method ofclaim 1799, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1829. The method of claim 1799, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1830. The method ofclaim 1799, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1831. The method ofclaim 1799, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1832. The method of claim 1799, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1833. Themethod of claim 1799, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1834. The method of claim 1799, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1835. Themethod of claim 1799, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1836. The methodof claim 1835, wherein at least about 20 heaters are disposed in theformation for each production well.
 1837. The method of claim 1799,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1838. The method of claim 1799,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1839. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using anatomic oxygen weight percentage of at least a portion of hydrocarbons inthe selected section, and wherein at least a portion of the hydrocarbonsin the selected section comprises an atomic oxygen weight percentage ofless than about 15% when measured on a dry, ash free basis; andproducing a mixture from the formation.
 1840. The method of claim 1839,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.1841. The method of claim 1839, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1842. The method of claim 1839, wherein the one or more heaterscomprise electrical heaters.
 1843. The method of claim 1839, wherein theone or more heaters comprise surface burners.
 1844. The method of claim1839, wherein the one or more heaters comprise flameless distributedcombustors.
 1845. The method of claim 1839, wherein the one or moreheaters comprise natural distributed combustors.
 1846. The method ofclaim 1839, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1847. The method ofclaim 1839, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1848. The method of claim 1839, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1849. The method of claim 1839, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1850. The method of claim 1839, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 1851. The method of claim 1839,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1852. The method of claim 1839,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1853. The method of claim 1839, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1854. The method of claim 1839,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1855. The method ofclaim 1839, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1856. Themethod of claim 1839, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1857. Themethod of claim 1839, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1858. Themethod of claim 1839, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1859. The method ofclaim 1839, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1860. The method of claim 1839, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1861. The methodof claim 1839, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1862. The method of claim1839, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1863. The method ofclaim 1839, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1864. The method of claim 1839, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1865.The method of claim 1839, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1866. The method of claim 1839, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1867. The method ofclaim 1866, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1868. The method ofclaim 1839, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1869. The method of claim 1839, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1870. The method ofclaim 1839, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1871. The method ofclaim 1839, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1872. The method of claim 1839, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1873. Themethod of claim 1839, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1874. The method of claim 1839,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1875. The method of claim 1839, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 1876.The method of claim 1875, wherein at least about 20 heaters are disposedin the formation for each production well.
 1877. The method of claim1839, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 1878. The method of claim1839, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1879. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto a selected section of the formation; allowing the heat to transferfrom the one or more heaters to the selected section of the formation topyrolyze hydrocarbon within the selected section; wherein at least somehydrocarbons within the selected section have an initial atomic oxygenweight percentage of less than about 15%; and producing a mixture fromthe formation.
 1880. The method of claim 1879, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 1881. The method of claim1879, further comprising maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 1882. The method of claim1879, wherein the one or more heaters comprise electrical heaters. 1883.The method of claim 1879, wherein the one or more heaters comprisesurface burners.
 1884. The method of claim 1879, wherein the one or moreheaters comprise flameless distributed combustors.
 1885. The method ofclaim 1879, wherein the one or more heaters comprise natural distributedcombustors.
 1886. The method of claim 1879, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1887. The method of claim 1879,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1888. The method of claim 1879, wherein providing heat fromthe one or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1889. The method of claim 1879, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1890.The method of claim 1879, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1891. The method of claim 1879, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1892. The method of claim 1879, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1893. The method of claim 1879, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1894. The method of claim 1879,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1895. The method ofclaim 1879, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1896. Themethod of claim 1879, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1897. Themethod of claim 1879, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1898. Themethod of claim 1879, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1899. The method ofclaim 1879, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1900. The method of claim 1879, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1901. The methodof claim 1879, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1902. The method of claim1879, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1903. The method ofclaim 1879, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1904. The method of claim 1879, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1905.The method of claim 1879, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1906. The method of claim 1879, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1907. The method ofclaim 1906, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1908. The method ofclaim 1879, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1909. The method of claim 1879, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1910. The method ofclaim 1879, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1911. The method ofclaim 1879, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1912. The method of claim 1879, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1913. Themethod of claim 1879, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1914. The method of claim 1879, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1915. Themethod of claim 1879, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1916. The methodof claim 1915, wherein at least about 20 heaters are disposed in theformation for each production well.
 1917. The method of claim 1879,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1918. The method of claim 1879,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1919. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using anatomic hydrogen to carbon ratio of at least a portion of hydrocarbons inthe selected section, wherein at least a portion of the hydrocarbons inthe selected section comprises an atomic hydrogen to carbon ratiogreater than about 0.70, and wherein the atomic hydrogen to carbon ratiois less than about 1.65; and producing a mixture from the formation.1920. The method of claim 1919, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 1921. The method of claim 1919, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 1922. The method of claim 1919, whereinthe one or more heaters comprise electrical heaters.
 1923. The method ofclaim 1919, wherein the one or more heaters comprise surface burners.1924. The method of claim 1919, wherein the one or more heaters compriseflameless distributed combustors.
 1925. The method of claim 1919,wherein the one or more heaters comprise natural distributed combustors.1926. The method of claim 1919, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1927. The method of claim 1919, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 1928. Themethod of claim 1919, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 1929. The method of claim 1919, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 1930.The method of claim 1919, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1931. The method of claim 1919, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1932. The method of claim 1919, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1933. The method of claim 1919, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1934. The method of claim 1919,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1935. The method ofclaim 1919, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1936. Themethod of claim 1919, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1937. Themethod of claim 1919, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1938. Themethod of claim 1919, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1939. The method ofclaim 1919, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1940. The method of claim 1919, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1941. The methodof claim 1919, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1942. The method of claim1919, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1943. The method ofclaim 1919, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1944. The method of claim 1919, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1945.The method of claim 1919, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1946. The method of claim 1919, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1947. The method ofclaim 1946, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1948. The method ofclaim 1919, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1949. The method of claim 1919, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1950. The method ofclaim 1919, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1951. The method ofclaim 1919, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1952. The method of claim 1919, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1953. Themethod of claim 1919, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1954. The method of claim 1919, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1955. Themethod of claim 1919, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1956. The methodof claim 1955, wherein at least about 20 heaters are disposed in theformation for each production well.
 1957. The method of claim 1919,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1958. The method of claim 1919,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1959. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto a selected section of the formation; allowing the heat to transferfrom the one or more heaters to the selected section of the formation topyrolyze hydrocarbons within the selected section; wherein at least somehydrocarbons within the selected section have an initial atomic hydrogento carbon ratio greater than about 0.70; wherein the initial atomichydrogen to carbon ration is less than about 1.65; and producing amixture from the formation.
 1960. The method of claim 1959, wherein theone or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 1961.The method of claim 1959, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1962.The method of claim 1959, wherein the one or more heaters compriseelectrical heaters.
 1963. The method of claim 1959, wherein the one ormore heaters comprise surface burners.
 1964. The method of claim 1959,wherein the one or more heaters comprise flameless distributedcombustors.
 1965. The method of claim 1959, wherein the one or moreheaters comprise natural distributed combustors.
 1966. The method ofclaim 1959, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1967. The method ofclaim 1959, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1968. The method of claim 1959, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 1969. The method of claim 1959, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 1970. The method of claim 1959, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 1971. The method of claim 1959,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 1972. The method of claim 1959,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1973. The method of claim 1959, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1974. The method of claim 1959,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1975. The method ofclaim 1959, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1976. Themethod of claim 1959, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1977. Themethod of claim 1959, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1978. Themethod of claim 1959, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1979. The method ofclaim 1959, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1980. The method of claim 1959, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1981. The methodof claim 1959, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1982. The method of claim1959, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1983. The method ofclaim 1959, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1984. The method of claim 1959, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1985.The method of claim 1959, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.1986. The method of claim 1959, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 1987. The method ofclaim 1986, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1988. The method ofclaim 1959, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1989. The method of claim 1959, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1990. The method ofclaim 1959, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1991. The method ofclaim 1959, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1992. The method of claim 1959, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1993. Themethod of claim 1959, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1994. The method of claim 1959, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1995. Themethod of claim 1959, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 1996. The methodof claim 1995, wherein at least about 20 heaters are disposed in theformation for each production well.
 1997. The method of claim 1959,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 1998. The method of claim 1959,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1999. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using anatomic oxygen to carbon ratio of at least a portion of hydrocarbons inthe selected section, wherein at least a portion of the hydrocarbons inthe selected section comprises an atomic oxygen to carbon ratio greaterthan about 0.025, and wherein the atomic oxygen to carbon ratio of atleast a portion of the hydrocarbons in the selected section is less thanabout 0.15; and producing a mixture from the formation.
 2000. The methodof claim 1999, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 2001. The method of claim 1999, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2002. The method of claim 1999, wherein the one ormore heaters comprise electrical heaters.
 2003. The method of claim1999, wherein the one or more heaters comprise surface burners. 2004.The method of claim 1999, wherein the one or more heaters compriseflameless distributed combustors.
 2005. The method of claim 1999,wherein the one or more heaters comprise natural distributed combustors.2006. The method of claim 1999, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2007. The method of claim 1999, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2008. Themethod of claim 1999, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2009. The method of claim 1999, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2010.The method of claim 1999, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2011. The method of claim 1999, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2012. The method of claim 1999, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2013. The method of claim 1999, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2014. The method of claim 1999,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2015. The method ofclaim 1999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2016. Themethod of claim 1999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2017. Themethod of claim 1999, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2018. Themethod of claim 1999, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2019. The method ofclaim 1999, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2020. The method of claim 1999, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2021. The methodof claim 1999, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2022. The method of claim1999, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2023. The method ofclaim 1999, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2024. The method of claim 1999, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2025.The method of claim 1999, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2026. The method of claim 1999, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2027. The method ofclaim 2026, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2028. The method ofclaim 1999, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2029. The method of claim 1999, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2030. The method ofclaim 1999, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2031. The method ofclaim 1999, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2032. The method of claim 1999, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2033. Themethod of claim 1999, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2034. The method of claim 1999,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2035. The method of claim 1999, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2036.The method of claim 2035, wherein at least about 20 heaters are disposedin the formation for each production well.
 2037. The method of claim1999, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2038. The method of claim1999, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2039. A method of treating a hydrocarbon containingformation in situ, comprising providing heat from one or more heaters toa selected section of the formation; allowing the heat to transfer fromthe one or more heaters to the selected section of the formation topyrolyze hydrocarbons within the selected section; wherein at least somehydrocarbons within the selected section have an initial atomic oxygento carbon ratio greater than about 0.025; wherein the initial atomicoxygen to carbon ratio is less than about 0.15; and producing a mixturefrom the formation.
 2040. The method of claim 2039, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 2041. The method of claim2039, further comprising maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 2042. The method of claim2039, wherein the one or more heaters comprise electrical heaters. 2043.The method of claim 2039, wherein the one or more heaters comprisesurface burners.
 2044. The method of claim 2039, wherein the one or moreheaters comprise flameless distributed combustors.
 2045. The method ofclaim 2039, wherein the one or more heaters comprise natural distributedcombustors.
 2046. The method of claim 2039, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2047. The method of claim 2039,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2048. The method of claim 2039, wherein providing heat fromthe one or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2049. The method of claim 2039, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2050.The method of claim 2039, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2051. The method of claim 2039, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2052. The method of claim 2039, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2053. The method of claim 2039, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2054. The method of claim 2039,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2055. The method ofclaim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2056. Themethod of claim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2057. Themethod of claim 2039, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2058. Themethod of claim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2059. The method ofclaim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2060. The method of claim 2039, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2061. The methodof claim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2062. The method of claim2039, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2063. The method ofclaim 2039, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2064. The method of claim 2039, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2065.The method of claim 2039, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2066. The method of claim 2039, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2067. The method ofclaim 2066, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2068. The method ofclaim 2039, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2069. The method of claim 2039, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2070. The method ofclaim 2039, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2071. The method ofclaim 2039, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2072. The method of claim 2039, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2073. Themethod of claim 2039, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2074. The method of claim 2039,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2075. The method of claim 2039, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2076.The method of claim 2075, wherein at least about 20 heaters are disposedin the formation for each production well.
 2077. The method of claim2039, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2078. The method of claim2039, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2079. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section has been selected for heating using amoisture content in the selected section, and wherein at least a portionof the selected section comprises a moisture content of less than about15% by weight; and producing a mixture from the formation.
 2080. Themethod of claim 2079, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 2081. The method of claim 2079, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2082. The method of claim 2079, wherein the one ormore heaters comprise electrical heaters.
 2083. The method of claim2079, wherein the one or more heaters comprise surface burners. 2084.The method of claim 2079, wherein the one or more heaters compriseflameless distributed combustors.
 2085. The method of claim 2079,wherein the one or more heaters comprise natural distributed combustors.2086. The method of claim 2079, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2087. The method of claim 2079, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2088. Themethod of claim 2079, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2089. The method of claim 2079, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2090.The method of claim 2079, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2091. The method of claim 2079, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2092. The method of claim 2079, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2093. The method of claim 2079, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2094. The method of claim 2079,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2095. The method ofclaim 2079, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2096. Themethod of claim 2079, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2097. Themethod of claim 2079, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2098. Themethod of claim 2079, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2099. The method ofclaim 2079, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2100. The method of claim 2079, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2101. The methodof claim 2079, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2102. The method of claim2079, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2103. The method ofclaim 2079, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2104. The method of claim 2079, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2105.The method of claim 2079, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2106. The method of claim 2079, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2107. The method ofclaim 2106, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2108. The method ofclaim 2079, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2109. The method of claim 2079, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2110. The method ofclaim 2079, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2111. The method ofclaim 2079, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2112. The method of claim 2079, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2113. Themethod of claim 2079, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2114. The method of claim 2079,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2115. The method of claim 2079, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2116.The method of claim 2115, wherein at least about 20 heaters are disposedin the formation for each production well.
 2117. The method of claim2079, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2118. The method of claim2079, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2119. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto a selected section of the formation; allowing the heat to transferfrom the one or more heaters to the selected section of the formation;wherein at least a portion of the selected section has an initialmoisture content of less than about 15% by weight; and producing amixture from the formation.
 2120. The method of claim 2119, wherein theone or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 2121.The method of claim 2119, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 2122.The method of claim 2119, wherein the one or more heaters compriseelectrical heaters.
 2123. The method of claim 2119, wherein the one ormore heaters comprise surface burners.
 2124. The method of claim 2119,wherein the one or more heaters comprise flameless distributedcombustors.
 2125. The method of claim 2119, wherein the one or moreheaters comprise natural distributed combustors.
 2126. The method ofclaim 2119, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2127. The method ofclaim 2119, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 2128. The method of claim 2119, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2129. The method of claim 2119, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 2130. The method of claim 2119, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 2131. The method of claim 2119,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 2132. The method of claim 2119,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2133. The method of claim 2119, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2134. The method of claim 2119,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2135. The method ofclaim 2119, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2136. Themethod of claim 2119, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2137. Themethod of claim 2119, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2138. Themethod of claim 2119, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2139. The method ofclaim 2119, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2140. The method of claim 2119, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2141. The methodof claim 2119, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2142. The method of claim2119, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2143. The method ofclaim 2119, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2144. The method of claim 2119, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2145.The method of claim 2119, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2146. The method of claim 2119, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2147. The method ofclaim 2146, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2148. The method ofclaim 2119, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2149. The method of claim 2119, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2150. The method ofclaim 2119, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2151. The method ofclaim 2119, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2152. The method of claim 2119, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2153. Themethod of claim 2119, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2154. The method of claim 2119,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2155. The method of claim 2119, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2156.The method of claim 2155, wherein at least about 20 heaters are disposedin the formation for each production well.
 2157. The method of claim2119, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2158. The method of claim2119, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2159. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;wherein the selected section is heated in a reducing environment duringat least a portion of the time that the selected section is beingheated; and producing a mixture from the formation.
 2160. The method ofclaim 2159, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 2161. The method of claim 2159, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2162. The method of claim 2159, wherein the one ormore heaters comprise electrical heaters.
 2163. The method of claim2159, wherein the one or more heaters comprise surface burners. 2164.The method of claim 2159, wherein the one or more heaters compriseflameless distributed combustors.
 2165. The method of claim 2159,wherein the one or more heaters comprise natural distributed combustors.2166. The method of claim 2159, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2167. The method of claim 2159, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2168. Themethod of claim 2159, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2169. The method of claim 2159, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2170.The method of claim 2159, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2171. The method of claim 2159, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2172. The method of claim 2159, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2173. The method of claim 2159, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2174. The method of claim 2159,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2175. The method ofclaim 2159, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2176. Themethod of claim 2159, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2177. Themethod of claim 2159, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2178. Themethod of claim 2159, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2179. The method ofclaim 2159, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2180. The method of claim 2159, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2181. The methodof claim 2159, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2182. The method of claim2159, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2183. The method ofclaim 2159, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2184. The method of claim 2159, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2185.The method of claim 2159, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2186. The method of claim 2159, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2187. The method ofclaim 2186, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2188. The method ofclaim 2159, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2189. The method of claim 2159, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2190. The method ofclaim 2159, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2191. The method ofclaim 2159, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2192. The method of claim 2159, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2193. Themethod of claim 2159, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2194. The method of claim 2159, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2195. Themethod of claim 2159, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 2196. The methodof claim 2195, wherein at least about 20 heaters are disposed in theformation for each production well.
 2197. The method of claim 2159,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 2198. The method of claim 2159,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2199. A method of treating a hydrocarbon containingformation in situ, comprising: heating a first section of the formationto produce a mixture from the formation; heating a second section of theformation; and recirculating a portion of the produced mixture from thefirst section into the second section of the formation to provide areducing environment within the second section of the formation. 2200.The method of claim 2199, further comprising maintaining a temperaturewithin the first section or the second section within a pyrolysistemperature range.
 2201. The method of claim 2199, wherein heating thefirst or the second section comprises heating with an electrical heater.2202. The method of claim 2199, wherein heating the first or the secondsection comprises heating with a surface burner.
 2203. The method ofclaim 2199, wherein heating the first or the second section comprisesheating with a flameless distributed combustor.
 2204. The method ofclaim 2199, wherein heating the first or the second section comprisesheating with a natural distributed combustor.
 2205. The method of claim2199, further comprising controlling a pressure and a temperature withinat least a majority of the first or second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2206. The method ofclaim 2199, further comprising controlling the heat such that an averageheating rate of the first or the second section is less than about 1° C.per day during pyrolysis.
 2207. The method of claim 2199, whereinheating the first or the second section comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from one or moreheaters, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/day (Pwr)provided to the selected volume is equal to or less thanh*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, and wherein anaverage heating rate (h) of the selected volume is about 10° C./day.2208. The method of claim 2199, wherein heating the first or the secondsection comprises transferring heat substantially by conduction. 2209.The method of claim 2199, wherein heating the first or the secondsection comprises heating the first or the second section such that athermal conductivity of at least a portion of the first or the secondsection is greater than about 0.5 W/(m ° C.).
 2210. The method of claim2199, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2211. The method of claim2199, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2212. The method of claim 2199,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2213. The method ofclaim 2199, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2214.The method of claim 2199, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2215. The method of claim 2199, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2216. The method of claim 2199, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2217. The method of claim 2199, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2218. The method of claim 2199, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2219. The method of claim 2199, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2220. The method of claim 2199, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2221. The method of claim 2199, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2222. The method of claim 2199, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2223. The method of claim2199, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2224. The method of claim 2199,further comprising controlling a pressure within at least a majority ofthe first or second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 2225. The method of claim2199, further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2226. The method of claim 2225, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2227. The method of claim 2199, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2228. The method of claim 2199, further comprising: providinghydrogen (H₂) to the first or second section to hydrogenate hydrocarbonswithin the first or second section; and heating a portion of the firstor second section with heat from hydrogenation.
 2229. The method ofclaim 2199, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2230. The method of claim 2199, wherein heating thefirst or the second section comprises increasing a permeability of amajority of the first or the second section to greater than about 100millidarcy.
 2231. The method of claim 2199, wherein heating the first orthe second section comprises substantially uniformly increasing apermeability of a majority of the first or the second section.
 2232. Themethod of claim 2199, further comprising controlling the heat to yieldgreater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 2233. The method of claim 2199, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 2234. The method of claim 2233, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 2235. The method of claim 2199, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 2236. The method of claim 2199, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2237. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; and allowing the heat to transfer from the one or moreheaters to a selected section of the formation such that a permeabilityof at least a portion of the selected section increases to greater thanabout 100 millidarcy.
 2238. The method of claim 2237, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 2239. The method of claim2237, further comprising maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 2240. The method of claim2237, wherein the one or more heaters comprise electrical heaters. 2241.The method of claim 2237, wherein the one or more heaters comprisesurface burners.
 2242. The method of claim 2237, wherein the one or moreheaters comprise flameless distributed combustors.
 2243. The method ofclaim 2237, wherein the one or more heaters comprise natural distributedcombustors.
 2244. The method of claim 2237, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2245. The method of claim 2237,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2246. The method of claim 2237, wherein providing heat fromthe one or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2247. The method of claim 2237, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2248.The method of claim 2237, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2249. The method of claim 2237, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2250. The method of claim 2237, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2251.The method of claim 2237, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2252. The method of claim 2237, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2253.The method of claim 2237, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2254. Themethod of claim 2237, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2255. Themethod of claim 2237, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2256. Themethod of claim 2237, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2257. The method ofclaim 2237, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2258. Themethod of claim 2237, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2259. The method of claim2237, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2260. The method of claim 2237, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2261. The method of claim 2237, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2262. The method of claim2237, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2263. The method of claim 2237, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2264. The method of claim 2237, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2265. The method of claim 2264, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2266. The method of claim 2237, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2267. The method of claim 2237, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2268. The method of claim 2237, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2269. The method of claim 2237, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2270. Themethod of claim 2237, further comprising increasing a permeability of amajority of the selected section to greater than about 5 Darcy. 2271.The method of claim 2237, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2272. The method of claim 2237,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2273. The method of claim 2237, further comprising producing a mixturein a production well, wherein at least about 7 heaters are disposed inthe formation for each production well.
 2274. The method of claim 2273,wherein at least about 20 heaters are disposed in the formation for eachproduction well.
 2275. The method of claim 2237, further comprisingproviding heat from three or more heaters to at least a portion of theformation, wherein three or more of the heaters are located in theformation in a unit of heaters, and wherein the unit of heaterscomprises a triangular pattern.
 2276. The method of claim 2237, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2277. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; and allowing the heat totransfer from the one or more heaters to a selected section of theformation such that a permeability of a majority of at least a portionof the selected section increases substantially uniformly.
 2278. Themethod of claim 2277, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 2279. The method of claim 2277, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2280. The method of claim 2277, wherein the one ormore heaters comprise electrical heaters.
 2281. The method of claim2277, wherein the one or more heaters comprise surface burners. 2282.The method of claim 2277, wherein the one or more heaters compriseflameless distributed combustors.
 2283. The method of claim 2277,wherein the one or more heaters comprise natural distributed combustors.2284. The method of claim 2277, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2285. The method of claim 2277, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2286. Themethod of claim 2277, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2287. The method of claim 2277, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2288.The method of claim 2277, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2289. The method of claim 2277, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2290. The method of claim 2277, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2291.The method of claim 2277, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2292. The method of claim 2277, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2293.The method of claim 2277, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2294. Themethod of claim 2277, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2295. Themethod of claim 2277, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2296. Themethod of claim 2277, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2297. The method ofclaim 2277, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2298. Themethod of claim 2277, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2299. The method of claim2277, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2300. The method of claim 2277, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2301. The method of claim 2277, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2302. The method of claim2277, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2303. The method of claim 2277, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2304. The method of claim 2277, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2305. The method of claim 2277, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2306. The method of claim 2277, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2307. The method of claim 2277, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2308. The method of claim 2277, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2309. The method of claim 2277, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2310. The method of claim2277, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2311. The method of claim 2277, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2312. Themethod of claim 2277, further comprising producing a mixture in aproduction well, wherein at least about 7 heaters are disposed in theformation for each production well.
 2313. The method of claim 2312,wherein at least about 20 heaters are disposed in the formation for eachproduction well.
 2314. The method of claim 2277, further comprisingproviding heat from three or more heaters to at least a portion of theformation, wherein three or more of the heaters are located in theformation in a unit of heaters, and wherein the unit of heaterscomprises a triangular pattern.
 2315. The method of claim 2277, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2316. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; and allowing the heat totransfer from the one or more heaters to a selected section of theformation such that a porosity of a majority of at least a portion ofthe selected section increases substantially uniformly.
 2317. The methodof claim 2316, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 2318. The method of claim 2316, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2319. The method of claim 2316, wherein the one ormore heaters comprise electrical heaters.
 2320. The method of claim2316, wherein the one or more heaters comprise surface burners. 2321.The method of claim 2316, wherein the one or more heaters compriseflameless distributed combustors.
 2322. The method of claim 2316,wherein the one or more heaters comprise natural distributed combustors.2323. The method of claim 2316, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2324. The method of claim 2316, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2325. Themethod of claim 2316, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2326. The method of claim 2316, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2327.The method of claim 2316, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2328. The method of claim 2316, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2329. The method of claim 2316, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2330.The method of claim 2316, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2331. The method of claim 2316, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2332.The method of claim 2316, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2333. Themethod of claim 2316, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2334. Themethod of claim 2316, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2335. Themethod of claim 2316, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2336. The method ofclaim 2316, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2337. Themethod of claim 2316, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2338. The method of claim2316, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2339. The method of claim 2316, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2340. The method of claim 2316, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2341. The method of claim2316, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2342. The method of claim 2316, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2343. The method of claim 2316, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2344. The method of claim 2316, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2345. The method of claim 2316, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2346. The method of claim 2316, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2347. The method of claim 2316, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2348. The method of claim 2316, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2349. The method of claim2316, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2350. The method of claim 2316, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2351. The method ofclaim 2316, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2352. The method of claim 2316, further comprisingproducing a mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2353.The method of claim 2352, wherein at least about 20 heaters are disposedin the formation for each production well.
 2354. The method of claim2316, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2355. The method of claim2316, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2356. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andcontrolling the heat to yield at least about 15% by weight of a totalorganic carbon content of at least some of the hydrocarbon containingformation into condensable hydrocarbons.
 2357. The method of claim 2356,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.2358. The method of claim 2356, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2359. The method of claim 2356, wherein the one or more heaterscomprise electrical heaters.
 2360. The method of claim 2356, wherein theone or more heaters comprise surface burners.
 2361. The method of claim2356, wherein the one or more heaters comprise flameless distributedcombustors.
 2362. The method of claim 2356, wherein the one or moreheaters comprise natural distributed combustors.
 2363. The method ofclaim 2356, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2364. The method ofclaim 2356, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 2365. The method of claim 2356, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2366. The method of claim 2356, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 2367. The method of claim 2356, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 2368. The method of claim 2356,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2369. The method of claim 2356, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 2370. The method of claim 2356, further comprising producing amixture from the formation, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2371. The method of claim 2356, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2372. The method of claim 2356, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2373. The method of claim 2356, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 2374. The method of claim 2356, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.2375. The method of claim 2356, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2376. The method ofclaim 2356, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2377. Themethod of claim 2356, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2378. The method of claim2356, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2379. The method of claim 2356, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2380. The method of claim 2356, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2381. The method of claim2356, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2382. The method of claim 2356, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2383. The method of claim 2356, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2384. The method of claim 2356, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2385. The method of claim 2356, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2386. The method of claim 2356, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2387. The method of claim 2356, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2388. The method of claim 2356, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2389. The method of claim2356, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2390. The method of claim 2356, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2391. The method ofclaim 2356, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2392. The method of claim 2356, further comprisingproducing a mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2393.The method of claim 2392, wherein at least about 20 heaters are disposedin the formation for each production well.
 2394. The method of claim2356, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2395. The method of claim2356, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2396. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2397. Themethod of claim 2396, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 2398. The method of claim 2396, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2399. The method of claim 2396, wherein the one ormore heaters comprise electrical heaters.
 2400. The method of claim2396, wherein the one or more heaters comprise surface burners. 2401.The method of claim 2396, wherein the one or more heaters compriseflameless distributed combustors.
 2402. The method of claim 2396,wherein the one or more heaters comprise natural distributed combustors.2403. The method of claim 2396, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2404. The method of claim 2396, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 2405. Themethod of claim 2396, wherein providing heat from the one or moreheaters to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2406. The method of claim 2396, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 2407.The method of claim 2396, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2408. The method of claim 2396, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2409. The method of claim 2396, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2410.The method of claim 2396, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2411. The method of claim 2396, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2412.The method of claim 2396, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2413. Themethod of claim 2396, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2414. Themethod of claim 2396, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2415. Themethod of claim 2396, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2416. The method ofclaim 2396, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2417. Themethod of claim 2396, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2418. The method of claim2396, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2419. The method of claim 2396, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2420. The method of claim 2396, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2421. The method of claim2396, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2422. The method of claim 2396, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2423. The method of claim 2396, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2424. The method of claim 2396, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2425. The method of claim 2396, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2426. The method of claim 2396, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2427. The method of claim 2396, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2428. The method of claim 2396, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2429. The method of claim2396, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2430. The method of claim 2396, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2431. The method ofclaim 2396, further comprising producing a mixture in a production well,and wherein at least about 7 heaters are disposed in the formation foreach production well.
 2432. The method of claim 2431, wherein at leastabout 20 heaters are disposed in the formation for each production well.2433. The method of claim 2396, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.2434. The method of claim 2396, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 2435. A method oftreating a hydrocarbon containing formation in situ, comprising: heatinga first section of the formation to pyrolyze at least some hydrocarbonsin the first section and produce a first mixture from the formation;heating a second section of the formation to pyrolyze at least somehydrocarbons in the second section and produce a second mixture from theformation; and leaving an unpyrolyzed section between the first sectionand the second section to inhibit subsidence of the formation.
 2436. Themethod of claim 2435, further comprising maintaining a temperaturewithin the first section or the second section within a pyrolysistemperature range.
 2437. The method of claim 2435, wherein heating thefirst section or heating the second section comprises heating with anelectrical heater.
 2438. The method of claim 2435, wherein heating thefirst section or heating the second section comprises heating with asurface burner.
 2439. The method of claim 2435, wherein heating thefirst section or heating the second section comprises heating with aflameless distributed combustor.
 2440. The method of claim 2435, whereinheating the first section or heating the second section comprisesheating with a natural distributed combustor.
 2441. The method of claim2435, further comprising controlling a pressure and a temperature withinat least a majority of the first or second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2442. The method ofclaim 2435, further comprising controlling the heat such that an averageheating rate of the first or second section is less than about 1° C. perday during pyrolysis.
 2443. The method of claim 2435, wherein heatingthe first section or heating the second section comprises: heating aselected volume (V) of the hydrocarbon containing formation from one ormore heaters, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2444. The method of claim 2435, wherein heating the firstsection or heating the second section comprises transferring heatsubstantially by conduction.
 2445. The method of claim 2435, whereinheating the first section or heating the second section comprisesheating the formation such that a thermal conductivity of at least aportion of the first or second section, respectively, is greater thanabout 0.5 W/(m ° C.).
 2446. The method of claim 2435, wherein the firstor second mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2447. The method of claim 2435, whereinthe first or second mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2448. The method of claim 2435, wherein thefirst or second mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2449. The method ofclaim 2435, wherein the first or second mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2450.The method of claim 2435, wherein the first or second mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2451. The method of claim 2435, wherein the first or secondmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2452. The method of claim 2435, wherein thefirst or second mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2453. The method of claim2435, wherein the first or second mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2454. The method ofclaim 2435, wherein the first or second mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2455. The method of claim 2435, wherein the first or secondmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 2456.The method of claim 2435, wherein the first or second mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 2457. Themethod of claim 2435, wherein the first or second mixture comprises anon-condensable component, and wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 2458.The method of claim 2435, wherein the first or second mixture comprisesammonia, and wherein greater than about 0.05% by weight of the first orsecond mixture is ammonia.
 2459. The method of claim 2435, wherein thefirst or second mixture comprises ammonia, and wherein the ammonia isused to produce fertilizer.
 2460. The method of claim 2435, furthercomprising controlling a pressure within at least a majority of thefirst or second section of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 2461. The method of claim2435, further comprising controlling formation conditions to produce thefirst or second mixture, wherein a partial pressure of H₂ within thefirst or second mixture is greater than about 0.5 bars.
 2462. The methodof claim 2435, wherein a partial pressure of H₂ within the first orsecond mixture is measured when the first or second mixture is at aproduction well.
 2463. The method of claim 2435, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2464. The method of claim 2435, further comprising controllingformation conditions by recirculating a portion of hydrogen from thefirst or second mixture into the formation.
 2465. The method of claim2435, further comprising: providing hydrogen (H₂) to the first or secondsection to hydrogenate hydrocarbons within the first or second section,respectively; and heating a portion of the first or second section,respectively, with heat from hydrogenation.
 2466. The method of claim2435, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2467. The method of claim 2435, wherein heating thefirst section or heating the second section comprises increasing apermeability of a majority of the first or second section, respectively,to greater than about 100 millidarcy.
 2468. The method of claim 2435,wherein heating the first section or heating the second sectioncomprises substantially uniformly increasing a permeability of amajority of the first or second section, respectively.
 2469. The methodof claim 2435, further comprising controlling heating of the first orsecond section to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay, from the first or secondsection, respectively.
 2470. The method of claim 2435, wherein producingthe first or second mixture comprises producing the first or secondmixture in a production well, and wherein at least about 7 heaters aredisposed in the formation for each production well.
 2471. The method ofclaim 2470, wherein at least about 20 heaters are disposed in theformation for each production well.
 2472. The method of claim 2435,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 2473. The method of claim 2435,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2474. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andproducing a mixture from the formation through one or more productionwells, wherein the heating is controlled such that the mixture can beproduced from the formation as a vapor, and wherein at least about 7heaters are disposed in the formation for each production well. 2475.The method of claim 2474, wherein at least about 20 heaters are disposedin the formation for each production well.
 2476. The method of claim2474, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.2477. The method of claim 2474, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2478. The method of claim 2474, wherein the one or more heaterscomprise electrical heaters.
 2479. The method of claim 2474, wherein theone or more heaters comprise surface burners.
 2480. The method of claim2474, wherein the one or more heaters comprise flameless distributedcombustors.
 2481. The method of claim 2474, wherein the one or moreheaters comprise natural distributed combustors.
 2482. The method ofclaim 2474, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2483. The method ofclaim 2474, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 2484. The method of claim 2474, wherein providing heatfrom the one or more heaters to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2485. The method of claim 2474, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 2486. The method of claim 2474, wherein providing heat fromthe one or more heaters comprises heating the selected section such thata thermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 2487. The method of claim 2474,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 2488. The method of claim 2474,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2489. The method of claim 2474, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2490. The method of claim 2474,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2491. The method ofclaim 2474, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2492. Themethod of claim 2474, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2493. Themethod of claim 2474, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2494. Themethod of claim 2474, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2495. The method ofclaim 2474, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2496. The method of claim 2474, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2497. The methodof claim 2474, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2498. The method of claim2474, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2499. The method ofclaim 2474, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2500. The method of claim 2474, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2501.The method of claim 2474, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2502. The method of claim 2474, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2503. The method ofclaim 2502, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2504. The method ofclaim 2474, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2505. The method of claim 2474, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2506. The method ofclaim 2474, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2507. The method ofclaim 2474, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2508. The method of claim 2474, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2509. Themethod of claim 2474, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2510. The method of claim 2474, wherein the heating iscontrolled to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 2511. The method ofclaim 2474, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, and whereinthe unit of heaters comprises a triangular pattern.
 2512. The method ofclaim 2474, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, wherein theunit of heaters comprises a triangular pattern, and wherein a pluralityof the units are repeated over an area of the formation to form arepetitive pattern of units.
 2513. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heaters to at least a portion of the formation, wherein the one ormore heaters are disposed within one or more first wells; allowing theheat to transfer from the one or more heaters to a selected section ofthe formation; and producing a mixture from the formation through one ormore second wells, wherein one or more of the first or second wells areinitially used for a first purpose and are then used for one or moreother purposes.
 2514. The method of claim 2513, wherein the firstpurpose comprises removing water from the formation, and wherein thesecond purpose comprises providing heat to the formation.
 2515. Themethod of claim 2513, wherein the first purpose comprises removing waterfrom the formation, and wherein the second purpose comprises producingthe mixture.
 2516. The method of claim 2513, wherein the first purposecomprises heating, and wherein the second purpose comprises removingwater from the formation.
 2517. The method of claim 2513, wherein thefirst purpose comprises producing the mixture, and wherein the secondpurpose comprises removing water from the formation.
 2518. The method ofclaim 2513, wherein the one or more heaters comprise electrical heaters.2519. The method of claim 2513, wherein the one or more heaters comprisesurface burners.
 2520. The method of claim 2513, wherein the one or moreheaters comprise flameless distributed combustors.
 2521. The method ofclaim 2513, wherein the one or more heaters comprise natural distributedcombustors.
 2522. The method of claim 2513, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2523. The method of claim 2513,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1.0° C. per day duringpyrolysis.
 2524. The method of claim 2513, wherein providing heat fromthe one or more heaters to at least the portion of the formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2525. The method of claim 2513, wherein providingheat from the one or more heaters comprises heating the selected sectionsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 2526. The method of claim2513, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 2527. The method of claim2513, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 2528. The method of claim 2513,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2529. The method ofclaim 2513, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2530.The method of claim 2513, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2531. The method of claim 2513, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2532. The method of claim 2513, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2533. The method of claim 2513, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2534. The method of claim 2513, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2535. The method of claim 2513, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2536. The method of claim 2513, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2537. The method of claim 2513, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2538. The method of claim 2513, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2539. The method of claim2513, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2540. The method of claim 2513,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2541. The method of claim 2513,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2542. The method ofclaim 2541, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 2543. The method of claim 2513, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2544. The method of claim 2513, furthercomprising controlling formation conditions, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 2545. The method of claim 2513, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2546. The method of claim 2513, whereinthe produced mixture comprises hydrogen and condensable hydrocarbons,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 2547. The method of claim 2513, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 2548. The methodof claim 2513, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2549. The method of claim 2513, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2550. Themethod of claim 2513, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for each production well.
 2551. The methodof claim 2550, wherein at least about 20 heaters are disposed in theformation for each production well.
 2552. The method of claim 2513,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 2553. The method of claim 2513,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2554. A method for forming heater wells in ahydrocarbon containing formation, comprising: forming a first wellborein the formation; forming a second wellbore in the formation usingmagnetic tracking such that the second wellbore is arrangedsubstantially parallel to the first wellbore; and providing at least oneheater within the first wellbore and at least one heater within thesecond wellbore such that the heaters can provide heat to at least aportion of the formation.
 2555. The method of claim 2554, whereinsuperposition of heat from the at least one heater within the firstwellbore and the at least one heater within the second wellborepyrolyzes at least some hydrocarbons within a selected section of theformation.
 2556. The method of claim 2554, further comprisingmaintaining a temperature within a selected section within a pyrolysistemperature range.
 2557. The method of claim 2554, wherein the heaterscomprise electrical heaters.
 2558. The method of claim 2554, wherein theheaters comprise surface burners.
 2559. The method of claim 2554,wherein the heaters comprise flameless distributed combustors.
 2560. Themethod of claim 2554, wherein the heaters comprise natural distributedcombustors.
 2561. The method of claim 2554, further comprisingcontrolling a pressure and a temperature within at least a majority of aselected section of the formation, wherein the pressure is controlled asa function of temperature, or the temperature is controlled as afunction of pressure.
 2562. The method of claim 2554, further comprisingcontrolling the heat from the heaters such that heat transferred fromthe heaters to at least the portion of the hydrocarbons is less thanabout 1° C. per day during pyrolysis.
 2563. The method of claim 2554,further comprising: heating a selected volume (V) of the hydrocarboncontaining formation from the heaters, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2564. The method of claim 2554, further comprisingallowing the heat to transfer from the heaters to at least the portionof the formation substantially by conduction.
 2565. The method of claim2554, further comprising providing heat from the heaters to at least theportion of the formation such that a thermal conductivity of at leastthe portion of the formation is greater than about 0.5 W/(m ° C.). 2566.The method of claim 2554, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2567. Themethod of claim 2554, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2568. The method of claim2554, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2569. The method of claim 2554,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2570. The method of claim 2554,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2571. The method of claim 2554,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2572. The method of claim 2554,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2573. The method of claim 2554, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2574.The method of claim 2554, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2575. The method of claim 2554, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2576. The method of claim2554, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2577. The method of claim 2554, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2578. The method of claim 2554, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2579. The method of claim2554, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2580. The method of claim 2554, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2581. The method of claim 2554, furthercomprising producing a mixture from the formation, wherein a partialpressure of H₂ within the mixture is greater than about 0.5 bars. 2582.The method of claim 2554, further comprising producing a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2583. The method ofclaim 2554, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2584. The method of claim 2554, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2585. The method of claim 2554, furthercomprising: providing hydrogen (H₂) to the portion to hydrogenatehydrocarbons within the formation; and heating a portion of theformation with heat from hydrogenation.
 2586. The method of claim 2554,further comprising: producing hydrogen and condensable hydrocarbons fromthe formation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2587. Themethod of claim 2554, further comprising allowing heat to transfer fromthe heaters to a selected section of the formation to pyrolyze at leastsome hydrocarbons within the selected section such that a permeabilityof a majority of a selected section of the formation increases togreater than about 100 millidarcy.
 2588. The method of claim 2554,further comprising allowing heat to transfer from the heaters to aselected section of the formation to pyrolyze at least some hydrocarbonswithin the selected section such that a permeability of a majority ofthe selected section increases substantially uniformly.
 2589. The methodof claim 2554, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2590. The method of claim 2554, further comprisingproducing a mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2591.The method of claim 2590, wherein at least about 20 heaters are disposedin the formation for each production well.
 2592. The method of claim2554, further comprising forming a production well in the formationusing magnetic tracking such that the production well is substantiallyparallel to the first wellbore and coupling a wellhead to the thirdwellbore.
 2593. The method of claim 2554, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 2594. The method of claim 2554, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2595. A methodfor installing a heater well into a hydrocarbon containing formation,comprising: forming a bore in the ground using a steerable motor and anaccelerometer; and providing a heater within the bore such that theheater can transfer heat to at least a portion of the formation. 2596.The method of claim 2595, further comprising installing at least twoheater wells, and wherein superposition of heat from at least the twoheater wells pyrolyzes at least some hydrocarbons within a selectedsection of the formation.
 2597. The method of claim 2595, furthercomprising maintaining a temperature within a selected section within apyrolysis temperature range.
 2598. The method of claim 2595, wherein theheater comprises an electrical heater.
 2599. The method of claim 2595,wherein the heater comprises a surface burner.
 2600. The method of claim2595, wherein the heater comprises a flameless distributed combustor.2601. The method of claim 2595, wherein the heater comprises a naturaldistributed combustor.
 2602. The method of claim 2595, furthercomprising controlling a pressure and a temperature within at least amajority of a selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2603. The method of claim 2595,further comprising controlling the heat from the heater such that heattransferred from the heater to at least the portion of the formation isless than about 1° C. per day during pyrolysis.
 2604. The method ofclaim 2595, further comprising: heating a selected volume (V) of thehydrocarbon containing formation from the heater, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2605. The method of claim 2595, further comprisingallowing the heat to transfer from the heater to at least the portion ofthe formation substantially by conduction.
 2606. The method of claim2595, further comprising providing heat from the heater to at least theportion of the formation such that a thermal conductivity of at leastthe portion of the formation is greater than about 0.5 W/(m ° C.). 2607.The method of claim 2595, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2608. Themethod of claim 2595, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2609. The method of claim2595, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2610. The method of claim 2595,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2611. The method of claim 2595,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2612. The method of claim 2595,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2613. The method of claim 2595,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2614. The method of claim 2595, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2615.The method of claim 2595, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2616. The method of claim 2595, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2617. The method of claim2595, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2618. The method of claim 2595, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2619. The method of claim 2595, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2620. The method of claim2595, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2621. The method of claim 2595, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2622. The method of claim 2595, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2623. The method of claim 2622, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2624. The method of claim 2595, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2625. The method of claim 2595, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2626. The method of claim 2595, furthercomprising: providing hydrogen (H₂) to the at least the heated portionto hydrogenate hydrocarbons within the formation; and heating a portionof the formation with heat from hydrogenation.
 2627. The method of claim2595, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2628. The method of claim 2595, further comprisingallowing heat to transfer from the heater to a selected section of theformation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of a selected section ofthe formation increases to greater than about 100 millidarcy.
 2629. Themethod of claim 2595, further comprising allowing heat to transfer fromthe heater to a selected section of the formation to pyrolyze at leastsome hydrocarbons within the selected section such that a permeabilityof a majority of the selected section increases substantially uniformly.2630. The method of claim 2595, further comprising controlling the heatto yield greater than about 60% by weight of condensable hydrocarbons,as measured by the Fischer Assay.
 2631. The method of claim 2595,further comprising producing a mixture in a production well, and whereinat least about 7 heaters are disposed in the formation for eachproduction well.
 2632. The method of claim 2631, wherein at least about20 heaters are disposed in the formation for each production well. 2633.The method of claim 2595, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 2634.The method of claim 2595, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2635. A method for installing ofwells in a hydrocarbon containing formation, comprising: forming awellbore in the formation by geosteered drilling; and providing a heaterwithin the wellbore such that the heater can transfer heat to at least aportion of the formation.
 2636. The method of claim 2635, furthercomprising maintaining a temperature within a selected section within apyrolysis temperature range.
 2637. The method of claim 2635, wherein theheater comprises an electrical heater.
 2638. The method of claim 2635,wherein the heater comprises a surface burner.
 2639. The method of claim2635, wherein the heater comprises a flameless distributed combustor.2640. The method of claim 2635, wherein the heater comprises a naturaldistributed combustor.
 2641. The method of claim 2635, furthercomprising controlling a pressure and a temperature within at least amajority of a selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2642. The method of claim 2635,further comprising controlling the heat from the heater such that heattransferred from the heater to at least the portion of the formation isless than about 1° C. per day during pyrolysis.
 2643. The method ofclaim 2635, further comprising: heating a selected volume (V) of thehydrocarbon containing formation from the heater, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2644. The method of claim 2635, further comprisingallowing the heat to transfer from the heater to at least the portion ofthe formation substantially by conduction.
 2645. The method of claim2635, further comprising providing heat from the heater to at least theportion of the formation such that a thermal conductivity of at leastthe portion of the formation is greater than about 0.5 W/(m ° C.). 2646.The method of claim 2635, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2647. Themethod of claim 2635, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2648. The method of claim2635, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2649. The method of claim 2635,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2650. The method of claim 2635,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2651. The method of claim 2635,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2652. The method of claim 2635,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2653. The method of claim 2635, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2654.The method of claim 2635, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2655. The method of claim 2635, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2656. The method of claim2635, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2657. The method of claim 2635, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2658. The method of claim 2635, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2659. The method of claim2635, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2660. The method of claim 2635, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bars absolute.
 2661. The method of claim 2635, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bars.
 2662. The method of claim 2661, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2663. The method of claim 2635, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2664. The method of claim 2635, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2665. The method of claim 2635, furthercomprising: providing hydrogen (H₂) to at least the heated portion tohydrogenate hydrocarbons within the formation; and heating a portion ofthe formation with heat from hydrogenation.
 2666. The method of claim2635, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2667. The method of claim 2635, further comprisingallowing heat to transfer from the heater to a selected section of theformation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of a selected section ofthe formation increases to greater than about 100 millidarcy.
 2668. Themethod of claim 2635, further comprising allowing heat to transfer fromthe heater to a selected section of the formation to pyrolyze at leastsome hydrocarbons within the selected section such that a permeabilityof a majority of the selected section increases substantially uniformly.2669. The method of claim 2635, further comprising controlling the heatto yield greater than about 60% by weight of condensable hydrocarbons,as measured by the Fischer Assay.
 2670. The method of claim 2635,further comprising producing a mixture in a production well, and whereinat least about 7 heaters are disposed in the formation for eachproduction well.
 2671. The method of claim 2670, wherein at least about20 heaters are disposed in the formation for each production well. 2672.The method of claim 2635, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 2673.The method of claim 2635, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2674. A method of treating ahydrocarbon containing formation in situ, comprising: heating a selectedsection of the formation with a heating element placed within awellbore, wherein at least one end of the heating element is free tomove axially within the wellbore to allow for thermal expansion of theheating element.
 2675. The method of claim 2674, further comprising atleast two heating elements within at least two wellbores, and whereinsuperposition of heat from at least the two heating elements pyrolyzesat least some hydrocarbons within a selected section of the formation.2676. The method of claim 2674, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2677. The method of claim 2674, wherein the heating elementcomprises a pipe-in-pipe heater.
 2678. The method of claim 2674, whereinthe heating element comprises a flameless distributed combustor. 2679.The method of claim 2674, wherein the heating element comprises amineral insulated cable coupled to a support, and wherein the support isfree to move within the wellbore.
 2680. The method of claim 2674,wherein the heating element comprises a mineral insulated cablesuspended from a wellhead.
 2681. The method of claim 2674, furthercomprising controlling a pressure and a temperature within at least amajority of a heated section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2682. The method of claim 2674,further comprising controlling the heat such that an average heatingrate of the heated section is less than about 1° C. per day duringpyrolysis.
 2683. The method of claim 2674, wherein heating the sectionof the formation further comprises: heating a selected volume (V) of thehydrocarbon containing formation from the heating element, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 2684. The method of claim 2674,wherein heating the section of the formation comprises transferring heatsubstantially by conduction.
 2685. The method of claim 2674, furthercomprising heating the selected section of the formation such that athermal conductivity of the selected section is greater than about 0.5W/(m ° C.).
 2686. The method of claim 2674, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2687. The method of claim 2674, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2688. The method of claim2674, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2689. The method of claim 2674,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2690. The method of claim 2674,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2691. The method of claim 2674,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2692. The method of claim 2674,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2693. The method of claim 2674, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2694.The method of claim 2674, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2695. The method of claim 2674, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2696. The method of claim2674, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2697. The method of claim 2674, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2698. The method of claim 2674, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2699. The method of claim2674, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2700. The method of claim 2674, furthercomprising controlling a pressure within the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 2701. The method of claim 2674, further comprising controllingformation conditions to produce a mixture from the formation, wherein apartial pressure of H₂ within the mixture is greater than about 0.5bars.
 2702. The method of claim 2701, wherein the partial pressure of H₂within the mixture is measured when the mixture is at a production well.2703. The method of claim 2674, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 2704. The methodof claim 2674, further comprising producing a mixture from the formationand controlling formation conditions by recirculating a portion ofhydrogen from the mixture into the formation.
 2705. The method of claim2674, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the heated section; and heating aportion of the section with heat from hydrogenation.
 2706. The method ofclaim 2674, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2707. The method of claim 2674, wherein heatingcomprises increasing a permeability of a majority of the heated sectionto greater than about 100 millidarcy.
 2708. The method of claim 2674,wherein heating comprises substantially uniformly increasing apermeability of a majority of the heated section.
 2709. The method ofclaim 2674, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2710. The method of claim 2674, further comprisingproducing a mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well. 2711.The method of claim 2710, wherein at least about 20 heaters are disposedin the formation for each production well.
 2712. The method of claim2674, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 2713. The method of claim2674, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2714. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation; andproducing a mixture from the formation through a production well,wherein the production well is located such that a majority of themixture produced from the formation comprises non-condensablehydrocarbons and a non-condensable component comprising hydrogen. 2715.The method of claim 2714, wherein the one or more heaters comprise atleast two heaters, and wherein superposition of heat from at least thetwo heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 2716. The method of claim 2714, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 2717. The method of claim 2714, whereinthe production well is less than approximately 6 m from a heater of theone or more heaters.
 2718. The method of claim 2714, wherein theproduction well is less than approximately 3 m from a heater of the oneor more heaters.
 2719. The method of claim 2714, wherein the productionwell is less than approximately 1.5 m from a heater of the one or moreheaters.
 2720. The method of claim 2714, wherein an additional heater ispositioned within a wellbore of the production well.
 2721. The method ofclaim 2714, wherein the one or more heaters comprise electrical heaters.2722. The method of claim 2714, wherein the one or more heaters comprisesurface burners.
 2723. The method of claim 2714, wherein the one or moreheaters comprise flameless distributed combustors.
 2724. The method ofclaim 2714, wherein the one or more heaters comprise natural distributedcombustors.
 2725. The method of claim 2714, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2726. The method of claim 2714,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2727. The method of claim 2714, wherein providing heat fromthe one or more heaters to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heaters, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 2728. The method of claim 2714, wherein allowing the heat totransfer from the one or more heaters to the selected section comprisestransferring heat substantially by conduction.
 2729. The method of claim2714, wherein providing heat from the one or more heaters comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2730. The method of claim 2714, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2731. The method of claim 2714, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2732.The method of claim 2714, wherein a molar ratio of ethene to ethane inthe non-condensable hydrocarbons ranges from about 0.001 to about 0.15.2733. The method of claim 2714, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2734. The method of claim 2714, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2735. The method of claim 2714, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2736. The method of claim 2714,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2737. The method of claim2714, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 2738. The method of claim 2714,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2739. Themethod of claim 2714, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2740. The method of claim2714, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2741. The method of claim 2714, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2742. The method of claim 2714, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2743. The method of claim2714, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2744. The method of claim 2714,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bars absolute.
 2745. The method of claim 2714,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bars.
 2746. The method of claim 2745, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2747. The method of claim 2714, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2748. The method of claim 2714, further comprising controllingformation conditions by recirculating a portion of the hydrogen from themixture into the formation.
 2749. The method of claim 2714, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2750. The method of claim 2714, furthercomprising: producing condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2751. The method of claim2714, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2752. The method of claim 2714, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2753. The method ofclaim 2714, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2754. The method of claim 2714, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heaters are disposed in the formation for eachproduction well.
 2755. The method of claim 2754, wherein at least about20 heaters are disposed in the formation for each production well. 2756.The method of claim 2714, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 2757.The method of claim 2714, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2758. A method of treating ahydrocarbon containing formation in situ, comprising: providing heat toat least a portion of the formation from one or more first heatersplaced within a pattern in the formation; allowing the heat to transferfrom the one or more first heaters to a first section of the formation;heating a second section of the formation with at least one secondheater, wherein the second section is located within the first section,and wherein at least the one second heater is configured to raise anaverage temperature of a portion of the second section to a highertemperature than an average temperature of the first section; andproducing a mixture from the formation through a production wellpositioned within the second section, wherein a majority of the producedmixture comprises non-condensable hydrocarbons and a non-condensablecomponent comprising H₂ components.
 2759. The method of claim 2758,wherein the one or more first heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the first section of the formation. 2760.The method of claim 2758, further comprising maintaining a temperaturewithin the first section within a pyrolysis temperature range.
 2761. Themethod of claim 2758, wherein at least the one heater comprises a heaterelement positioned within the production well.
 2762. The method of claim2758, wherein at least the one second heater comprises an electricalheater.
 2763. The method of claim 2758, wherein at least the one secondheater comprises a surface burner.
 2764. The method of claim 2758,wherein at least the one second heater comprises a flameless distributedcombustor.
 2765. The method of claim 2758, wherein at least the onesecond heater comprises a natural distributed combustor.
 2766. Themethod of claim 2758, further comprising controlling a pressure and atemperature within at least a majority of the first or the secondsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2767. The method of claim 2758, further comprisingcontrolling the heat such that an average heating rate of the firstsection is less than about 1° C. per day during pyrolysis.
 2768. Themethod of claim 2758, wherein providing heat to the formation furthercomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more first heaters, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 2769. The method of claim 2758, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 2770. The method of claim 2758, wherein providing heat fromthe one or more first heaters comprises heating the first section suchthat a thermal conductivity of at least a portion of the first sectionis greater than about 0.5 W/(m ° C.).
 2771. The method of claim 2758,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 2772. The method of claim 2758,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2773. The method of claim 2758, wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2774. The method of claim 2758,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2775. The method ofclaim 2758, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2776. Themethod of claim 2758, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2777. Themethod of claim 2758, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2778. Themethod of claim 2758, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2779. The method ofclaim 2758, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2780. The method of claim 2758, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2781. The methodof claim 2758, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2782. The method of claim2758, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2783. The method ofclaim 2758, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2784. The method of claim 2758, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2785.The method of claim 2758, further comprising controlling a pressurewithin at least a majority of the first or the second section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 2786. The method of claim 2758, further comprising controllingformation conditions to produce the mixture, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bars.
 2787. Themethod of claim 2786, wherein the partial pressure of H₂ within themixture is measured when the mixture is at a production well.
 2788. Themethod of claim 2758, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 2789. The method of claim2758, further comprising controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2790. The method of claim 2758, further comprising: providing hydrogen(H₂) to the first or second section to hydrogenate hydrocarbons withinthe first or second section, respectively; and heating a portion of thefirst or second section, respectively, with heat from hydrogenation.2791. The method of claim 2758, further comprising: producingcondensable hydrocarbons from the formation; and hydrogenating a portionof the produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2792. The method of claim 2758, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe first or second section to greater than about 100 millidarcy. 2793.The method of claim 2758, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the first or second section.
 2794. The method of claim 2758,wherein heating the first or the second section is controlled to yieldgreater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 2795. The method of claim 2758, whereinat least about 7 heaters are disposed in the formation for eachproduction well.
 2796. The method of claim 2795, wherein at least about20 heaters are disposed in the formation for each production well. 2797.The method of claim 2758, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 2798.The method of claim 2758, further comprising providing heat from threeor more heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2799. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatinto the formation from a plurality of heaters placed in a patternwithin the formation, wherein a spacing between heaters is greater thanabout 6 m; allowing the heat to transfer from the plurality of heatersto a selected section of the formation; producing a mixture from theformation from a plurality of production wells, wherein the plurality ofproduction wells are positioned within the pattern, and wherein aspacing between production wells is greater than about 12 m.
 2800. Themethod of claim 2799, wherein superposition of heat from the pluralityof heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 2801. The method of claim 2799, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 2802. The method of claim 2799, whereinthe plurality of heaters comprises electrical heaters.
 2803. The methodof claim 2799, wherein the plurality of heaters comprises surfaceburners.
 2804. The method of claim 2799, wherein the plurality ofheaters comprises flameless distributed combustors.
 2805. The method ofclaim 2799, wherein the plurality of heaters comprises naturaldistributed combustors.
 2806. The method of claim 2799, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2807. The method of claim 2799,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2808. The method of claim 2799, wherein providing heat fromthe plurality of heaters comprises: heating a selected volume (V) of thehydrocarbon containing formation from the plurality of heaters, whereinthe formation has an average heat capacity (C_(v)), and wherein theheating pyrolyzes at least some hydrocarbons within the selected volumeof the formation; and wherein heating energy/day (Pwr) provided to theselected volume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B)is formation bulk density, and wherein an average heating rate (h) ofthe selected volume is about 10° C./day.
 2809. The method of claim 2799,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 2810. The method of claim 2799, whereinproviding heat comprises heating the selected formation such that athermal conductivity of at least a portion of the selected section isgreater than about 0.5 W/(m ° C.).
 2811. The method of claim 2799,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 2812. The method of claim 2799,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2813. The method of claim 2799, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2814. The method of claim 2799,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2815. The method ofclaim 2799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2816. Themethod of claim 2799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2817. Themethod of claim 2799, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2818. Themethod of claim 2799, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2819. The method ofclaim 2799, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2820. The method of claim 2799, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2821. The methodof claim 2799, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2822. The method of claim2799, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2823. The method ofclaim 2799, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2824. The method of claim 2799, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2825.The method of claim 2799, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.2826. The method of claim 2799, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bars.
 2827. The method ofclaim 2826, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2828. The method ofclaim 2799, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2829. The method of claim 2799, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2830. The method ofclaim 2799, further comprising: providing hydrogen (H₂) to the selectedsection to hydrogenate hydrocarbons within the selected section; andheating a portion of the selected section with heat from hydrogenation.2831. The method of claim 2799, further comprising: producing hydrogenand condensable hydrocarbons from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 2832. The method of claim 2799, whereinallowing the heat to transfer comprises increasing a permeability of amajority of the selected section to greater than about 100 millidarcy.2833. The method of claim 2799, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2834. The method of claim 2799,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2835. The method of claim 2799, wherein at least about 7 heaters aredisposed in the formation for each production well.
 2836. The method ofclaim 2835, wherein at least about 20 heaters are disposed in theformation for each production well.
 2837. The method of claim 2799,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 2838. The method of claim 2799,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2839. A system configured to heat a hydrocarboncontaining formation, comprising: a heater disposed in an opening in theformation, wherein the heater is configured to provide heat to at leasta portion of the formation during use; an oxidizing fluid source; aconduit disposed in the opening, wherein the conduit is configured toprovide an oxidizing fluid from the oxidizing fluid source to a reactionzone in the formation during use, and wherein the oxidizing fluid isselected to oxidize at least some hydrocarbons at the reaction zoneduring use such that heat is generated at the reaction zone; and whereinthe system is configured to allow heat to transfer substantially byconduction from the reaction zone to a pyrolysis zone of the formationduring use.
 2840. The system of claim 2839, wherein the oxidizing fluidis configured to generate heat in the reaction zone such that theoxidizing fluid is transported through the reaction zone substantiallyby diffusion.
 2841. The system of claim 2839, wherein the conduitcomprises orifices, and wherein the orifices are configured to providethe oxidizing fluid into the opening.
 2842. The system of claim 2839,wherein the conduit comprises critical flow orifices, and wherein thecritical flow orifices are configured to control a flow of the oxidizingfluid such that a rate of oxidation in the formation is controlled.2843. The system of claim 2839, wherein the conduit is furtherconfigured to be cooled with the oxidizing fluid such that the conduitis not substantially heated by oxidation.
 2844. The system of claim2839, wherein the conduit is further configured to remove an oxidationproduct.
 2845. The system of claim 2839, wherein the conduit is furtherconfigured to remove an oxidation product such that the oxidationproduct transfers substantial heat to the oxidizing fluid.
 2846. Thesystem of claim 2839, wherein the conduit is further configured toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2847. The system of claim 2839,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2848. The system of claim 2839, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2849. The system of claim 2839,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2850. The system ofclaim 2839, further comprising a center conduit disposed within theconduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 2851. Thesystem of claim 2839, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2852. The system of claim 2839, further comprising a conductor disposedin a second conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configured to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2853. The system of claim 2839, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configured to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2854. The system of claim 2839, further comprising at least oneelongated member disposed within the opening, wherein the at least theone elongated member is configured to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2855. The system of claim 2839, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configured to heat the oxidizing fluid, whereinthe conduit is further configured to provide the heated oxidizing fluidinto the opening during use, and wherein the heated oxidizing fluid isconfigured to heat at least a portion of the formation during use. 2856.The system of claim 2839, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2857. The system of claim 2839, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2858. The system of claim2839, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2859. The system of claim 2839, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2860. The system ofclaim 2839, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2861. The system of claim2839, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2862. The system of claim 2839, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2863. A system configurable to heata hydrocarbon containing formation, comprising: a heater configurable tobe disposed in an opening in the formation, wherein the heater isfurther configurable to provide heat to at least a portion of theformation during use; a conduit configurable to be disposed in theopening, wherein the conduit is configurable to provide an oxidizingfluid from an oxidizing fluid source to a reaction zone in the formationduring use, and wherein the system is configurable to allow theoxidizing fluid to oxidize at least some hydrocarbons at the reactionzone during use such that heat is generated at the reaction zone; andwherein the system is further configurable to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 2864. The system of claim 2863, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 2865. The system of claim 2863, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 2866. The system of claim2863, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 2867. The system of claim 2863, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 2868. The system ofclaim 2863, wherein the conduit is further configurable to remove anoxidation product.
 2869. The system of claim 2863, wherein the conduitis further configurable to remove an oxidation product, such that theoxidation product transfers heat to the oxidizing fluid.
 2870. Thesystem of claim 2863, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2871. The system of claim 2863,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2872. The system of claim 2863, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2873. The system of claim 2863,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2874. The system ofclaim 2863, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 2875.The system of claim 2863, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2876. The system of claim 2863, further comprising a conductor disposedin a second conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configurable to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2877. The system of claim 2863, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configurable to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2878. The system of claim 2863, further comprising at least oneelongated member disposed within the opening, wherein the at least theone elongated member is configurable to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2879. The system of claim 2863, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configurable to heat the oxidizing fluid, whereinthe conduit is further configurable to provide the heated oxidizingfluid into the opening during use, and wherein the heated oxidizingfluid is configurable to heat at least a portion of the formation duringuse.
 2880. The system of claim 2863, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 2881. The system of claim 2863,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2882. The system of claim2863, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2883. The system of claim 2863, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2884. The system ofclaim 2863, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2885. The system of claim2863, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2886. The system of claim 2863, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 2887. The system of claim 2863,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a heater disposed in anopening in the formation, wherein the heater is configured to provideheat to at least a portion of the formation during use; an oxidizingfluid source; a conduit disposed in the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 2888. An in situ method for heating ahydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.2889. The method of claim 2888, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 2890. The methodof claim 2888, further comprising directing at least a portion of theoxidizing fluid into the opening through orifices of a conduit disposedin the opening.
 2891. The method of claim 2888, further comprisingcontrolling a flow of the oxidizing fluid with critical flow orifices ofa conduit disposed in the opening such that a rate of oxidation iscontrolled.
 2892. The method of claim 2888, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.2893. The method of claim 2888, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid to reduce heating of the conduit by oxidation.
 2894. Themethod of claim 2888, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit.
 2895. The method of claim 2888, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit andtransferring heat from the oxidation product in the conduit to oxidizingfluid in the conduit.
 2896. The method of claim 2888, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit, wherein aflow rate of the oxidizing fluid in the conduit is approximately equalto a flow rate of the oxidation product in the conduit.
 2897. The methodof claim 2888, wherein a conduit is disposed within the opening, themethod further comprising removing an oxidation product from theformation through the conduit and controlling a pressure between theoxidizing fluid and the oxidation product in the conduit to reducecontamination of the oxidation product by the oxidizing fluid.
 2898. Themethod of claim 2888, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and substantially inhibiting the oxidationproduct from flowing into portions of the formation beyond the reactionzone.
 2899. The method of claim 2888, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 2900. The method of claim 2888,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 2901. The method of claim 2888, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 2902. The method of claim 2888, wherein heating theportion comprises applying electrical current to a conductor disposed ina conduit, wherein the conduit is disposed within the opening.
 2903. Themethod of claim 2888, wherein heating the portion comprises applyingelectrical current to an insulated conductor disposed within theopening.
 2904. The method of claim 2888, wherein heating the portioncomprises applying electrical current to at least one elongated memberdisposed within the opening.
 2905. The method of claim 2888, whereinheating the portion comprises heating the oxidizing fluid in a heatexchanger disposed external to the formation such that providing theoxidizing fluid into the opening comprises transferring heat from theheated oxidizing fluid to the portion.
 2906. The method of claim 2888,further comprising removing water from the formation prior to heatingthe portion.
 2907. The method of claim 2888, further comprisingcontrolling the temperature of the formation to substantially inhibitproduction of oxides of nitrogen during oxidation.
 2908. The method ofclaim 2888, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation.
 2909. The method of claim 2888, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 2910. The method of claim 2888,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 2911. Themethod of claim 2888, further comprising coupling an overburden casingto the opening, wherein a packing material is disposed at a junction ofthe overburden casing and the opening.
 2912. The method of claim 2888,wherein the pyrolysis zone is substantially adjacent to the reactionzone.
 2913. A system configured to heat a hydrocarbon containingformation, comprising: a heater disposed in an opening in the formation,wherein the heater is configured to provide heat to at least a portionof the formation during use; an oxidizing fluid source; a conduitdisposed in the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone, and wherein the conduit isfurther configured to remove an oxidation product from the formationduring use; and wherein the system is configured to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 2914. The system of claim2913, wherein the oxidizing fluid is configured to generate heat in thereaction zone such that the oxidizing fluid is transported through thereaction zone substantially by diffusion.
 2915. The system of claim2913, wherein the conduit comprises orifices, and wherein the orificesare configured to provide the oxidizing fluid into the opening. 2916.The system of claim 2913, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configured tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2917. The system of claim 2913, wherein theconduit is further configured to be cooled with the oxidizing fluid suchthat the conduit is not substantially heated by oxidation.
 2918. Thesystem of claim 2913, wherein the conduit is further configured suchthat the oxidation product transfers heat to the oxidizing fluid. 2919.The system of claim 2913, wherein a flow rate of the oxidizing fluid inthe conduit is approximately equal to a flow rate of the oxidationproduct in the conduit.
 2920. The system of claim 2913, wherein apressure of the oxidizing fluid in the conduit and a pressure of theoxidation product in the conduit are controlled to reduce contaminationof the oxidation product by the oxidizing fluid.
 2921. The system ofclaim 2913, wherein the oxidation product is substantially inhibitedfrom flowing into portions of the formation beyond the reaction zone.2922. The system of claim 2913, wherein the oxidizing fluid issubstantially inhibited from flowing into portions of the formationbeyond the reaction zone.
 2923. The system of claim 2913, furthercomprising a center conduit disposed within the conduit, wherein thecenter conduit is configured to provide the oxidizing fluid into theopening during use.
 2924. The system of claim 2913, wherein the portionof the formation extends radially from the opening a width of less thanapproximately 0.2 m.
 2925. The system of claim 2913, further comprisinga conductor disposed in a second conduit, wherein the second conduit isdisposed within the opening, and wherein the conductor is configured toheat at least a portion of the formation during application of anelectrical current to the conductor.
 2926. The system of claim 2913,further comprising an insulated conductor disposed within the opening,wherein the insulated conductor is configured to heat at least a portionof the formation during application of an electrical current to theinsulated conductor.
 2927. The system of claim 2913, further comprisingat least one elongated member disposed within the opening, wherein theat least the one elongated member is configured to heat at least aportion of the formation during application of an electrical current tothe at least the one elongated member.
 2928. The system of claim 2913,further comprising a heat exchanger disposed external to the formation,wherein the heat exchanger is configured to heat the oxidizing fluid,wherein the conduit is further configured to provide the heatedoxidizing fluid into the opening during use, and wherein the heatedoxidizing fluid is configured to heat at least a portion of theformation during use.
 2929. The system of claim 2913, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2930. The systemof claim 2913, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2931.The system of claim 2913, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2932. The system of claim 2913, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2933. The system of claim 2913, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 2934. The system of claim 2913, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 2935. Thesystem of claim 2913, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 2936. A system configurable to heat a hydrocarboncontaining formation, comprising: a heater configurable to be disposedin an opening in the formation, wherein the heater is furtherconfigurable to provide heat to at least a portion of the formationduring use; a conduit configurable to be disposed in the opening,wherein the conduit is further configurable to provide an oxidizingfluid from an oxidizing fluid source to a reaction zone in the formationduring use, wherein the system is configurable to allow the oxidizingfluid to oxidize at least some hydrocarbons at the reaction zone duringuse such that heat is generated at the reaction zone, and wherein theconduit is further configurable to remove an oxidation product from theformation during use; and wherein the system is further configurable toallow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone during use.
 2937. The system of claim 2936,wherein the oxidizing fluid is configurable to generate heat in thereaction zone such that the oxidizing fluid is transported through thereaction zone substantially by diffusion.
 2938. The system of claim2936, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 2939.The system of claim 2936, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2940. The system of claim 2936, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 2941.The system of claim 2936, wherein the conduit is further configurablesuch that the oxidation product transfers heat to the oxidizing fluid.2942. The system of claim 2936, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2943. The system of claim 2936,wherein a pressure of the oxidizing fluid in the conduit and a pressureof the oxidation product in the conduit are controlled to reducecontamination of the oxidation product by the oxidizing fluid.
 2944. Thesystem of claim 2936, wherein the oxidation product is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 2945. The system of claim 2936, wherein the oxidizingfluid is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2946. The system of claim 2936,further comprising a center conduit disposed within the conduit, whereinthe center conduit is configurable to provide the oxidizing fluid intothe opening during use.
 2947. The system of claim 2936, wherein theportion of the formation extends radially from the opening a width ofless than approximately 0.2 m.
 2948. The system of claim 2936, furthercomprising a conductor disposed in a second conduit, wherein the secondconduit is disposed within the opening, and wherein the conductor isconfigurable to heat at least a portion of the formation duringapplication of an electrical current to the conductor.
 2949. The systemof claim 2936, further comprising an insulated conductor disposed withinthe opening, wherein the insulated conductor is configurable to heat atleast a portion of the formation during application of an electricalcurrent to the insulated conductor.
 2950. The system of claim 2936,further comprising at least one elongated member disposed within theopening, wherein the at least the one elongated member is configurableto heat at least a portion of the formation during application of anelectrical current to the at least the one elongated member.
 2951. Thesystem of claim 2936, further comprising a heat exchanger disposedexternal to the formation, wherein the heat exchanger is configurable toheat the oxidizing fluid, wherein the conduit is further configurable toprovide the heated oxidizing fluid into the opening during use, andwherein the heated oxidizing fluid is configurable to heat at least aportion of the formation during use.
 2952. The system of claim 2936,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation.2953. The system of claim 2936, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 2954. The system of claim 2936, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2955. The system of claim 2936, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2956. The system of claim 2936, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 2957. The system of claim 2936, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.2958. The system of claim 2936, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2959. The system of claim 2936,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a heater disposed in anopening in the formation, wherein the heater is configured to provideheat to at least a portion of the formation during use; an oxidizingfluid source; a conduit disposed in the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, wherein the oxidizingfluid is selected to oxidize at least some hydrocarbons at the reactionzone during use such that heat is generated at the reaction zone, andwherein the conduit is further configured to remove an oxidation productfrom the formation during use; and wherein the system is configured toallow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 2960. An in situmethod for heating a hydrocarbon containing formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons within the portion of the formationwith an oxidizing fluid, wherein the portion is located substantiallyadjacent to an opening in the formation; providing the oxidizing fluidto a reaction zone in the formation; allowing the oxidizing gas to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat in the reaction zone; removing at least a portion of anoxidation product through the opening; and transferring the generatedheat substantially by conduction from the reaction zone to a pyrolysiszone in the formation.
 2961. The method of claim 2960, furthercomprising transporting the oxidizing fluid through the reaction zone bydiffusion.
 2962. The method of claim 2960, further comprising directingat least a portion of the oxidizing fluid into the opening throughorifices of a conduit disposed in the opening.
 2963. The method of claim2960, further comprising controlling a flow of the oxidizing fluid withcritical flow orifices of a conduit disposed in the opening such that arate of oxidation is controlled.
 2964. The method of claim 2960, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially maintained within the reaction zone.2965. The method of claim 2960, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2966. The method of claim 2960, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit.
 2967. The methodof claim 2960, wherein a conduit is disposed within the opening, andwherein removing at least the portion of the oxidation product throughthe opening comprises removing at least the portion of the oxidationproduct through the conduit, the method further comprising transferringsubstantial heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 2968. The method of claim 2960, whereina conduit is disposed within the opening, wherein removing at least theportion of the oxidation product through the opening comprises removingat least the portion of the oxidation product through the conduit, andwherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 2969. The method of claim 2960, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit, the method furthercomprising controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 2970. The method of claim2960, wherein a conduit is disposed within the opening, and whereinremoving at least the portion of the oxidation product through theopening comprises removing at least the portion of the oxidation productthrough the conduit, the method further comprising substantiallyinhibiting the oxidation product from flowing into portions of theformation beyond the reaction zone.
 2971. The method of claim 2960,further comprising substantially inhibiting the oxidizing fluid fromflowing into portions of the formation beyond the reaction zone. 2972.The method of claim 2960, wherein a center conduit is disposed within anouter conduit, and wherein the outer conduit is disposed within theopening, the method further comprising providing the oxidizing fluidinto the opening through the center conduit and removing at least aportion of the oxidation product through the outer conduit.
 2973. Themethod of claim 2960, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2974. The method of claim 2960, wherein heating the portion comprisesapplying electrical current to a conductor disposed in a conduit,wherein the conduit is disposed within the opening.
 2975. The method ofclaim 2960, wherein heating the portion comprises applying electricalcurrent to an insulated conductor disposed within the opening.
 2976. Themethod of claim 2960, wherein heating the portion comprises applyingelectrical current to at least one elongated member disposed within theopening.
 2977. The method of claim 2960, wherein heating the portioncomprises heating the oxidizing fluid in a heat exchanger disposedexternal to the formation such that providing the oxidizing fluid intothe opening comprises transferring heat from the heated oxidizing fluidto the portion.
 2978. The method of claim 2960, further comprisingremoving water from the formation prior to heating the portion. 2979.The method of claim 2960, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 2980. The method of claim 2960, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 2981.The method of claim 2960, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 2982. The method of claim 2960, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 2983. The method of claim 2960,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 2984. The method of claim 2960, wherein the pyrolysiszone is substantially adjacent to the reaction.
 2985. A systemconfigured to heat a hydrocarbon containing formation, comprising: anelectric heater disposed in an opening in the formation, wherein theelectric heater is configured to provide heat to at least a portion ofthe formation during use; an oxidizing fluid source; a conduit disposedin the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 2986.The system of claim 2985, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 2987.The system of claim 2985, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 2988. The system of claim 2985, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2989. The system of claim2985, wherein the conduit is further configured to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2990. The system of claim 2985, wherein the conduit isfurther configured to remove an oxidation product.
 2991. The system ofclaim 2985, wherein the conduit is further configured to remove anoxidation product, such that the oxidation product transfers heat to theoxidizing fluid.
 2992. The system of claim 2985, wherein the conduit isfurther configured to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 2993. The system ofclaim 2985, wherein the conduit is further configured to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 2994. The system of claim 2985, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 2995. The system of claim2985, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2996.The system of claim 2985, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 2997.The system of claim 2985, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2998. The system of claim 2985, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2999. The system of claim 2985, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3000. The system of claim2985, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3001. The system of claim 2985, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3002. The system ofclaim 2985, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3003. The system of claim2985, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3004. The system of claim 2985, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3005. A system configurable to heata hydrocarbon containing formation, comprising: an electric heaterconfigurable to be disposed in an opening in the formation, wherein theelectric heater is further configurable to provide heat to at least aportion of the formation during use, and wherein at least the portion islocated substantially adjacent to the opening; a conduit configurable tobe disposed in the opening, wherein the conduit is further configurableto provide an oxidizing fluid from an oxidizing fluid source to areaction zone in the formation during use, and wherein the system isconfigurable to allow the oxidizing fluid to oxidize at least somehydrocarbons at the reaction zone during use such that heat is generatedat the reaction zone; and wherein the system is further configurable toallow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 3006. The systemof claim 3005, wherein the oxidizing fluid is configurable to generateheat in the reaction zone such that the oxidizing fluid is transportedthrough the reaction zone substantially by diffusion.
 3007. The systemof claim 3005, wherein the conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening.
 3008. The system of claim 3005, wherein the conduit comprisescritical flow orifices, and wherein the critical flow orifices areconfigurable to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3009. The system of claim3005, wherein the conduit is further configurable to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 3010. The system of claim 3005, wherein the conduit isfurther configurable to remove an oxidation product.
 3011. The system ofclaim 3005, wherein the conduit is further configurable to remove anoxidation product such that the oxidation product transfers heat to theoxidizing fluid.
 3012. The system of claim 3005, wherein the conduit isfurther configurable to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 3013. The system ofclaim 3005, wherein the conduit is further configurable to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3014. The system of claim 3005, wherein the conduit isfurther configurable to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3015. The system of claim3005, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3016.The system of claim 3005, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configurable toprovide the oxidizing fluid into the opening during use, and wherein theconduit is further configurable to remove an oxidation product duringuse.
 3017. The system of claim 3005, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3018. The system of claim 3005, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3019. The systemof claim 3005, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3020.The system of claim 3005, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3021. The system of claim 3005, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3022. The system of claim 3005, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3023. The system of claim 3005, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3024. The system of claim 3005, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3025. The system of claim 3005,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: an electric heater disposedin an opening in the formation, wherein the electric heater isconfigured to provide heat to at least a portion of the formation duringuse; an oxidizing fluid source; a conduit disposed in the opening,wherein the conduit is configured to provide an oxidizing fluid from theoxidizing fluid source to a reaction zone in the formation during use,and wherein the oxidizing fluid is selected to oxidize at least somehydrocarbons at the reaction zone during use such that heat is generatedat the reaction zone; and wherein the system is configured to allow heatto transfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3026. A system configured toheat a hydrocarbon containing formation, comprising: a conductordisposed in a first conduit, wherein the first conduit is disposed in anopening in the formation, and wherein the conductor is configured toprovide heat to at least a portion of the formation during use; anoxidizing fluid source; a second conduit disposed in the opening,wherein the second conduit is configured to provide an oxidizing fluidfrom the oxidizing fluid source to a reaction zone in the formationduring use, and wherein the oxidizing fluid is selected to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is configuredto allow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 3027. The systemof claim 3026, wherein the oxidizing fluid is configured to generateheat in the reaction zone such that the oxidizing fluid is transportedthrough the reaction zone substantially by diffusion.
 3028. The systemof claim 3026, wherein the second conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 3029. The system of claim 3026, wherein the second conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3030. The system of claim3026, wherein the second conduit is further configured to be cooled withthe oxidizing fluid to reduce heating of the second conduit byoxidation.
 3031. The system of claim 3026, wherein the second conduit isfurther configured to remove an oxidation product.
 3032. The system ofclaim 3026, wherein the second conduit is further configured to removean oxidation product such that the oxidation product transfers heat tothe oxidizing fluid.
 3033. The system of claim 3026, wherein the secondconduit is further configured to remove an oxidation product, andwherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in thesecond conduit.
 3034. The system of claim 3026, wherein the secondconduit is further configured to remove an oxidation product, andwherein a pressure of the oxidizing fluid in the second conduit and apressure of the oxidation product in the second conduit are controlledto reduce contamination of the oxidation product by the oxidizing fluid.3035. The system of claim 3026, wherein the second conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3036. The system of claim 3026,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3037. The system ofclaim 3026, further comprising a center conduit disposed within thesecond conduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the secondconduit is further configured to remove an oxidation product during use.3038. The system of claim 3026, wherein the portion of the formationextends radially from the opening a width of less than approximately 0.2m.
 3039. The system of claim 3026, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 3040. The system of claim 3026,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3041. The system of claim3026, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3042. The system of claim 3026, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3043. The system ofclaim 3026, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3044. The system of claim3026, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3045. The system of claim 3026, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3046. A system configurable to heata hydrocarbon containing formation, comprising: a conductor configurableto be disposed in a first conduit, wherein the first conduit isconfigurable to be disposed in an opening in the formation, and whereinthe conductor is further configurable to provide heat to at least aportion of the formation during use; a second conduit configurable to bedisposed in the opening, wherein the second conduit is furtherconfigurable to provide an oxidizing fluid from an oxidizing fluidsource to a reaction zone in the formation during use, and wherein thesystem is configurable to allow the oxidizing fluid to oxidize at leastsome hydrocarbons at the reaction zone during use such that heat isgenerated at the reaction zone; and wherein the system is furtherconfigurable to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3047.The system of claim 3046, wherein the oxidizing fluid is configurable togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3048.The system of claim 3046, wherein the second conduit comprises orifices,and wherein the orifices are configurable to provide the oxidizing fluidinto the opening.
 3049. The system of claim 3046, wherein the secondconduit comprises critical flow orifices, and wherein the critical floworifices are configurable to control a flow of the oxidizing fluid suchthat a rate of oxidation in the formation is controlled.
 3050. Thesystem of claim 3046, wherein the second conduit is further configurableto be cooled with the oxidizing fluid to reduce heating of the secondconduit by oxidation.
 3051. The system of claim 3046, wherein the secondconduit is further configurable to remove an oxidation product. 3052.The system of claim 3046, wherein the second conduit is furtherconfigurable to remove an oxidation product such that the oxidationproduct transfers heat to the oxidizing fluid.
 3053. The system of claim3046, wherein the second conduit is further configurable to remove anoxidation product, and wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the second conduit.
 3054. The system of claim 3046, wherein thesecond conduit is further configurable to remove an oxidation product,and wherein a pressure of the oxidizing fluid in the second conduit anda pressure of the oxidation product in the second conduit are controlledto reduce contamination of the oxidation product by the oxidizing fluid.3055. The system of claim 3046, wherein the second conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3056. The system of claim 3046,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3057. The system ofclaim 3046, further comprising a center conduit disposed within thesecond conduit, wherein the center conduit is configurable to providethe oxidizing fluid into the opening during use, and wherein the secondconduit is further configurable to remove an oxidation product duringuse.
 3058. The system of claim 3046, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3059. The system of claim 3046, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3060. The systemof claim 3046, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3061.The system of claim 3046, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3062. The system of claim 3046, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3063. The system of claim 3046, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3064. The system of claim 3046, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3065. The system of claim 3046, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3066. The system of claim 3046,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a conductor disposed in afirst conduit, wherein the first conduit is disposed in an opening inthe formation, and wherein the conductor is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a second conduit disposed in the opening, wherein the secondconduit is configured to provide an oxidizing fluid from the oxidizingfluid source to a reaction zone in the formation during use, and whereinthe oxidizing fluid is selected to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3067. An in situ method for heating ahydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises applying an electrical current to aconductor disposed in a first conduit to provide heat to the portion,and wherein the first conduit is disposed within the opening; providingthe oxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons atthe reaction zone to generate heat at the reaction zone; andtransferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3068. The method ofclaim 3067, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3069. The method of claim 3067, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a second conduit disposed in the opening.3070. The method of claim 3067, further comprising controlling a flow ofthe oxidizing fluid with critical flow orifices of a second conduitdisposed in the opening such that a rate of oxidation is controlled.3071. The method of claim 3067, further comprising increasing a flow ofthe oxidizing fluid in the opening to accommodate an increase in avolume of the reaction zone such that a rate of oxidation issubstantially constant over time within the reaction zone.
 3072. Themethod of claim 3067, wherein a second conduit is disposed in theopening, the method further comprising cooling the second conduit withthe oxidizing fluid to reduce heating of the second conduit byoxidation.
 3073. The method of claim 3067, wherein a second conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the second conduit. 3074.The method of claim 3067, wherein a second conduit is disposed withinthe opening, the method further comprising removing an oxidation productfrom the formation through the second conduit and transferring heat fromthe oxidation product in the conduit to the oxidizing fluid in thesecond conduit.
 3075. The method of claim 3067, wherein a second conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the second conduit,wherein a flow rate of the oxidizing fluid in the second conduit isapproximately equal to a flow rate of the oxidation product in thesecond conduit.
 3076. The method of claim 3067, wherein a second conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the second conduit andcontrolling a pressure between the oxidizing fluid and the oxidationproduct in the second conduit to reduce contamination of the oxidationproduct by the oxidizing fluid.
 3077. The method of claim 3067, whereina second conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and substantially inhibiting the oxidation product from flowinginto portions of the formation beyond the reaction zone.
 3078. Themethod of claim 3067, further comprising substantially inhibiting theoxidizing fluid from flowing into portions of the formation beyond thereaction zone.
 3079. The method of claim 3067, wherein a center conduitis disposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3080. The method ofclaim 3067, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3081. The methodof claim 3067, further comprising removing water from the formationprior to heating the portion.
 3082. The method of claim 3067, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3083. Themethod of claim 3067, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3084. The method of claim 3067, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3085. The method of claim3067, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3086. The method of claim 3067, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3087. A systemconfigured to heat a hydrocarbon containing formation, comprising: aninsulated conductor disposed in an opening in the formation, wherein theinsulated conductor is configured to provide heat to at least a portionof the formation during use; an oxidizing fluid source; a conduitdisposed in the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3088.The system of claim 3087, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3089.The system of claim 3087, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 3090. The system of claim 3087, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3091. The system of claim3087, wherein the conduit is configured to be cooled with the oxidizingfluid such that the conduit is not substantially heated by oxidation.3092. The system of claim 3087, wherein the conduit is furtherconfigured to remove an oxidation product.
 3093. The system of claim3087, wherein the conduit is further configured to remove an oxidationproduct, and wherein the conduit is further configured such that theoxidation product transfers substantial heat to the oxidizing fluid.3094. The system of claim 3087, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 3095. The system of claim 3087,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the secondconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3096. The system of claim 3087, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3097. The system of claim3087, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3098.The system of claim 3087, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 3099.The system of claim 3087, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3100. The system of claim 3087, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3101. The system of claim 3087, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3102. The system of claim3087, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3103. The system of claim 3087, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3104. The system ofclaim 3087, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3105. The system of claim3087, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3106. The system of claim 3087, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3107. A system configurable to heata hydrocarbon containing formation, comprising: an insulated conductorconfigurable to be disposed in an opening in the formation, wherein theinsulated conductor is further configurable to provide heat to at leasta portion of the formation during use; a conduit configurable to bedisposed in the opening, wherein the conduit is further configurable toprovide an oxidizing fluid from an oxidizing fluid source to a reactionzone in the formation during use, and wherein the system is configurableto allow the oxidizing fluid to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3108. The system of claim3107, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 3109. The system of claim3107, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 3110.The system of claim 3107, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 3111. The system of claim 3107, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 3112.The system of claim 3107, wherein the conduit is further configurable toremove an oxidation product.
 3113. The system of claim 3107, wherein theconduit is further configurable to remove an oxidation product, suchthat the oxidation product transfers heat to the oxidizing fluid. 3114.The system of claim 3107, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3115. The system of claim 3107,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3116. The system of claim 3107, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3117. The system of claim 3107,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3118. The system ofclaim 3107, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configurable to remove an oxidation product during use. 3119.The system of claim 3107, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3120. The system of claim 3107, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3121. The system of claim 3107, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3122. The system of claim3107, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3123. The system of claim 3107, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3124. The system ofclaim 3107, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3125. The system of claim3107, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3126. The system of claim 3107, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 3127. The system of claim 3107,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: an insulated conductordisposed in an opening in the formation, wherein the insulated conductoris configured to provide heat to at least a portion of the formationduring use; an oxidizing fluid source; a conduit disposed in theopening, wherein the conduit is configured to provide an oxidizing fluidfrom the oxidizing fluid source to a reaction zone in the formationduring use, and wherein the oxidizing fluid is selected to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is configuredto allow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 3128. An in situmethod for heating a hydrocarbon containing formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons within the portion of the formationwith an oxidizing fluid, wherein heating comprises applying anelectrical current to an insulated conductor to provide heat to theportion, and wherein the insulated conductor is disposed within theopening; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.3129. The method of claim 3128, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 3130. The methodof claim 3128, further comprising directing at least a portion of theoxidizing fluid into the opening through orifices of a conduit disposedin the opening.
 3131. The method of claim 3128, further comprisingcontrolling a flow of the oxidizing fluid with critical flow orifices ofa conduit disposed in the opening such that a rate of oxidation iscontrolled.
 3132. The method of claim 3128, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.3133. The method of claim 3128, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid to reduce heating of the conduit by oxidation.
 3134. Themethod of claim 3128, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit.
 3135. The method of claim 3128, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit andtransferring heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 3136. The method of claim 3128, whereina conduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit,wherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 3137. The method of claim 3128, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit and controlling apressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3138. The method of claim 3128, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3139. The method ofclaim 3128, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3140. The method of claim 3128, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3141. The method ofclaim 3128, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3142. The methodof claim 3128, further comprising removing water from the formationprior to heating the portion.
 3143. The method of claim 3128, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3144. Themethod of claim 3128, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3145. The method of claim 3128, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3146. The method of claim3128, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3147. The method of claim 3128, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3148. The methodof claim 3128, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3149. An in situ method for heating a hydrocarboncontaining formation, comprising: heating a portion of the formation toa temperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein the portion islocated substantially adjacent to an opening in the formation, whereinheating comprises applying an electrical current to an insulatedconductor to provide heat to the portion, wherein the insulatedconductor is coupled to a conduit, wherein the conduit comprisescritical flow orifices, and wherein the conduit is disposed within theopening; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.3150. The method of claim 3149, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 3151. The methodof claim 3149, further comprising controlling a flow of the oxidizingfluid with the critical flow orifices such that a rate of oxidation iscontrolled.
 3152. The method of claim 3149, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.3153. The method of claim 3149, further comprising cooling the conduitwith the oxidizing fluid to reduce heating of the conduit by oxidation.3154. The method of claim 3149, further comprising removing an oxidationproduct from the formation through the conduit.
 3155. The method ofclaim 3149, further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3156. Themethod of claim 3149, further comprising removing an oxidation productfrom the formation through the conduit, wherein a flow rate of theoxidizing fluid in the conduit is approximately equal to a flow rate ofthe oxidation product in the conduit.
 3157. The method of claim 3149,further comprising removing an oxidation product from the formationthrough the conduit and controlling a pressure between the oxidizingfluid and the oxidation product in the conduit to reduce contaminationof the oxidation product by the oxidizing fluid.
 3158. The method ofclaim 3149, further comprising removing an oxidation product from theformation through the conduit and substantially inhibiting the oxidationproduct from flowing into portions of the formation beyond the reactionzone.
 3159. The method of claim 3149, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3160. The method of claim 3149,wherein a center conduit is disposed within the conduit, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theconduit.
 3161. The method of claim 3149, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3162. The method of claim 3149, further comprisingremoving water from the formation prior to heating the portion. 3163.The method of claim 3149, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3164. The method of claim 3149, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3165.The method of claim 3149, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3166. The method of claim 3149, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3167. The method of claim 3149,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3168. The method of claim 3149, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3169. A systemconfigured to heat a hydrocarbon containing formation, comprising: atleast one elongated member disposed in an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a conduit disposed in the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3170. The system of claim 3169, wherein theoxidizing fluid is configured to generate heat in the reaction zone suchthat the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 3171. The system of claim 3169, wherein theconduit comprises orifices, and wherein the orifices are configured toprovide the oxidizing fluid into the opening.
 3172. The system of claim3169, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configured to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 3173. The system of claim 3169, wherein the conduit isfurther configured to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 3174. The system ofclaim 3169, wherein the conduit is further configured to remove anoxidation product.
 3175. The system of claim 3169, wherein the conduitis further configured to remove an oxidation product such that theoxidation product transfers heat to the oxidizing fluid.
 3176. Thesystem of claim 3169, wherein the conduit is further configured toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3177. The system of claim 3169,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3178. The system of claim 3169, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3179. The system of claim 3169,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3180. The system ofclaim 3169, further comprising a center conduit disposed within theconduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 3181. Thesystem of claim 3169, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3182. The system of claim 3169, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3183. The system of claim 3169, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3184. The system of claim3169, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3185. The system of claim 3169, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3186. The system ofclaim 3169, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3187. The system of claim3169, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3188. The system of claim 3169, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3189. A system configurable to heata hydrocarbon containing formation, comprising: at least one elongatedmember configurable to be disposed in an opening in the formation,wherein at least the one elongated member is further configurable toprovide heat to at least a portion of the formation during use; aconduit configurable to be disposed in the opening, wherein the conduitis further configurable to provide an oxidizing fluid from the oxidizingfluid source to a reaction zone in the formation during use, and whereinthe system is configurable to allow the oxidizing fluid to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is furtherconfigurable to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3190.The system of claim 3189, wherein the oxidizing fluid is configurable togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3191.The system of claim 3189, wherein the conduit comprises orifices, andwherein the orifices are configurable to provide the oxidizing fluidinto the opening.
 3192. The system of claim 3189, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configurable to control a flow of the oxidizing fluid such that arate of oxidation in the formation is controlled.
 3193. The system ofclaim 3189, wherein the conduit is further configurable to be cooledwith the oxidizing fluid such that the conduit is not substantiallyheated by oxidation.
 3194. The system of claim 3189, wherein the conduitis further configurable to remove an oxidation product.
 3195. The systemof claim 3189, wherein the conduit is further configurable to remove anoxidation product such that the oxidation product transfers heat to theoxidizing fluid.
 3196. The system of claim 3189, wherein the conduit isfurther configurable to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 3197. The system ofclaim 3189, wherein the conduit is further configurable to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3198. The system of claim 3189, wherein the conduit isfurther configurable to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3199. The system of claim3189, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3200.The system of claim 3189, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configurable toprovide the oxidizing fluid into the opening during use, and wherein theconduit is further configurable to remove an oxidation product duringuse.
 3201. The system of claim 3189, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3202. The system of claim 3189, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3203. The systemof claim 3189, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3204.The system of claim 3189, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3205. The system of claim 3189, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3206. The system of claim 3189, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3207. The system of claim 3189, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3208. The system of claim 3189, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3209. The system of claim 3189,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: at least one elongatedmember disposed in an opening in the formation, wherein at least the oneelongated member is configured to provide heat to at least a portion ofthe formation during use; an oxidizing fluid source; a conduit disposedin the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3210.An in situ method for heating a hydrocarbon containing formation,comprising: heating a portion of the formation to a temperaturesufficient to support reaction of hydrocarbons within the portion of theformation with an oxidizing fluid, wherein heating comprises applying anelectrical current to at least one elongated member to provide heat tothe portion, and wherein at least the one elongated member is disposedwithin the opening; providing the oxidizing fluid to a reaction zone inthe formation; allowing the oxidizing fluid to react with at least aportion of the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.3211. The method of claim 3210, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 3212. The methodof claim 3210, further comprising directing at least a portion of theoxidizing fluid into the opening through orifices of a conduit disposedin the opening.
 3213. The method of claim 3210, further comprisingcontrolling a flow of the oxidizing fluid with critical flow orifices ofa conduit disposed in the opening such that a rate of oxidation iscontrolled.
 3214. The method of claim 3210, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.3215. The method of claim 3210, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid to reduce heating of the conduit by oxidation.
 3216. Themethod of claim 3210, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit.
 3217. The method of claim 3210, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit andtransferring heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 3218. The method of claim 3210, whereina conduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit,wherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 3219. The method of claim 3210, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit and controlling apressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3220. The method of claim 3210, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3221. The method ofclaim 3210, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3222. The method of claim 3210, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3223. The method ofclaim 3210, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3224. The methodof claim 3210, further comprising removing water from the formationprior to heating the portion.
 3225. The method of claim 3210, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3226. Themethod of claim 3210, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3227. The method of claim 3210, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3228. The method of claim3210, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3229. The method of claim 3210, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3230. The methodof claim 3210, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3231. A system configured to heat a hydrocarboncontaining formation, comprising: a heat exchanger disposed external tothe formation, wherein the heat exchanger is configured to heat anoxidizing fluid during use; a conduit disposed in the opening, whereinthe conduit is configured to provide the heated oxidizing fluid from theheat exchanger to at least a portion of the formation during use,wherein the system is configured to allow heat to transfer from theheated oxidizing fluid to at least the portion of the formation duringuse, and wherein the oxidizing fluid is selected to oxidize at leastsome hydrocarbons at a reaction zone in the formation during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3232.The system of claim 3231, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3233.The system of claim 3231, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 3234. The system of claim 3231, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3235. The system of claim3231, wherein the conduit is further configured to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 3236. The system of claim 3231, wherein the conduit isfurther configured to remove an oxidation product.
 3237. The system ofclaim 3231, wherein the conduit is further configured to remove anoxidation product, such that the oxidation product transfers heat to theoxidizing fluid.
 3238. The system of claim 3231, wherein the conduit isfurther configured to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 3239. The system ofclaim 3231, wherein the conduit is further configured to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3240. The system of claim 3231, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3241. The system of claim3231, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3242.The system of claim 3231, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 3243.The system of claim 3231, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3244. The system of claim 3231, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3245. The system of claim 3231, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3246. The system of claim3231, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3247. The system of claim 3231, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3248. The system ofclaim 3231, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3249. The system of claim3231, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3250. A system configurable to heat a hydrocarboncontaining formation, comprising: a heat exchanger configurable to bedisposed external to the formation, wherein the heat exchanger isfurther configurable to heat an oxidizing fluid during use; a conduitconfigurable to be disposed in the opening, wherein the conduit isfurther configurable to provide the heated oxidizing fluid from the heatexchanger to at least a portion of the formation during use, wherein thesystem is configurable to allow heat to transfer from the heatedoxidizing fluid to at least the portion of the formation during use, andwherein the system is further configurable to allow the oxidizing fluidto oxidize at least some hydrocarbons at a reaction zone in theformation during use such that heat is generated at the reaction zone;and wherein the system is further configurable to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3251. The system of claim 3250, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 3252. The system of claim 3250, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 3253. The system of claim3250, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 3254. The system of claim 3250, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 3255. The system ofclaim 3250, wherein the conduit is further configurable to remove anoxidation product.
 3256. The system of claim 3250, wherein the conduitis further configurable to remove an oxidation product such that theoxidation product transfers heat to the oxidizing fluid.
 3257. Thesystem of claim 3250, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3258. The system of claim 3250,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3259. The system of claim 3250, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3260. The system of claim 3250,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3261. The system ofclaim 3250, further comprising a center conduit disposed within theconduit, wherein the center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the secondconduit is further configurable to remove an oxidation product duringuse.
 3262. The system of claim 3250, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3263. The system of claim 3250, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3264. The systemof claim 3250, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3265.The system of claim 3250, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3266. The system of claim 3250, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3267. The system of claim 3250, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3268. The system of claim 3250, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3269. The system of claim 3250, wherein the system is configured to heata hydrocarbon containing formation, and wherein the system comprises: aheat exchanger disposed external to the formation, wherein the heatexchanger is configured to heat an oxidizing fluid during use; a conduitdisposed in the opening, wherein the conduit is configured to providethe heated oxidizing fluid from the heat exchanger to at least a portionof the formation during use, wherein the system is configured to allowheat to transfer from the heated oxidizing fluid to at least the portionof the formation during use, and wherein the oxidizing fluid is selectedto oxidize at least some hydrocarbons at a reaction zone in theformation during use such that heat is generated at the reaction zone;and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3270. An in situ method for heating ahydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises: heating the oxidizing fluid with aheat exchanger, wherein the heat exchanger is disposed external to theformation; providing the heated oxidizing fluid from the heat exchangerto the portion of the formation; and allowing heat to transfer from theheated oxidizing fluid to the portion of the formation; providing theoxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons atthe reaction zone to generate heat at the reaction zone; andtransferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3271. The method ofclaim 3270, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3272. The method of claim 3270, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3273. Themethod of claim 3270, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3274. The method ofclaim 3270, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3275. The method of claim 3270, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3276. The method of claim 3270, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3277. Themethod of claim 3270, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3278. Themethod of claim 3270, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3279. The method of claim 3270,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3280. The method of claim3270, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3281. The method of claim 3270, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3282. The method of claim 3270,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3283. The method of claim 3270, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3284. The method of claim 3270, further comprisingremoving water from the formation prior to heating the portion. 3285.The method of claim 3270, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3286. The method of claim 3270, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3287.The method of claim 3270, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3288. The method of claim 3270, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3289. The method of claim 3270,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3290. The method of claim 3270, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3291. An in situmethod for heating a hydrocarbon containing formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons within the portion of the formationwith an oxidizing fluid, wherein heating comprises: oxidizing a fuel gasin a heater, wherein the heater is disposed external to the formation;providing the oxidized fuel gas from the heater to the portion of theformation; and allowing heat to transfer from the oxidized fuel gas tothe portion of the formation; providing the oxidizing fluid to areaction zone in the formation; allowing the oxidizing fluid to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 3292. The method of claim 3291, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.3293. The method of claim 3291, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 3294. The method of claim 3291, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 3295. The method of claim 3291, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 3296. The method of claim 3291, wherein a conduit isdisposed in the opening, the method further comprising cooling theconduit with the oxidizing fluid to reduce heating of the conduit byoxidation.
 3297. The method of claim 3291, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit.
 3298. The method ofclaim 3291, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and transferring heat from the oxidation product inthe conduit to the oxidizing fluid in the conduit.
 3299. The method ofclaim 3291, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 3300. The method of claim 3291, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit and controllinga pressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3301. The method of claim 3291, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3302. The method ofclaim 3291, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3303. The method of claim 3291, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3304. The method ofclaim 3291, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3305. The methodof claim 3291, further comprising removing water from the formationprior to heating the portion.
 3306. The method of claim 3291, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3307. Themethod of claim 3291, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3308. The method of claim 3291, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3309. The method of claim3291, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3310. The method of claim 3291, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3311. The methodof claim 3291, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3312. A system configured to heat a hydrocarboncontaining formation, comprising: an insulated conductor disposed withinan open wellbore in the formation, wherein the insulated conductor isconfigured to provide radiant heat to at least a portion of theformation during use; and wherein the system is configured to allow heatto transfer from the insulated conductor to a selected section of theformation during use.
 3313. The system of claim 3312, wherein theinsulated conductor is further configured to generate heat duringapplication of an electrical current to the insulated conductor duringuse.
 3314. The system of claim 3312, further comprising a supportmember, wherein the support member is configured to support theinsulated conductor.
 3315. The system of claim 3312, further comprisinga support member and a centralizer, wherein the support member isconfigured to support the insulated conductor, and wherein thecentralizer is configured to maintain a location of the insulatedconductor on the support member.
 3316. The system of claim 3312, whereinthe open wellbore comprises a diameter of at least approximately 5 cm.3317. The system of claim 3312, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a low resistance conductor configured to generatesubstantially no heat.
 3318. The system of claim 3312, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a rubber insulated conductor.3319. The system of claim 3312, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a copper wire.
 3320. The system of claim 3312, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor.
 3321. The system of claim 3312, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3322. Thesystem of claim 3312, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath.
 3323. Thesystem of claim 3312, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3324. The system of claim3312, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3325. The system of claim 3312, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3326. The system of claim 3312,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3327. Thesystem of claim 3312, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3328.The system of claim 3312, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3329. The system of claim 3312, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3330. The system of claim 3312, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configured to occupyporous spaces within the magnesium oxide.
 3331. The system of claim3312, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3332. The system of claim3312, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3333. The system of claim 3312, furthercomprising two additional insulated conductors, wherein the insulatedconductor and the two additional insulated conductors are configured ina 3-phase Y configuration.
 3334. The system of claim 3312, furthercomprising an additional insulated conductor, wherein the insulatedconductor and the additional insulated conductor are coupled to asupport member, and wherein the insulated conductor and the additionalinsulated conductor are configured in a series electrical configuration.3335. The system of claim 3312, further comprising an additionalinsulated conductor, wherein the insulated conductor and the additionalinsulated conductor are coupled to a support member, and wherein theinsulated conductor and the additional insulated conductor areconfigured in a parallel electrical configuration.
 3336. The system ofclaim 3312, wherein the insulated conductor is configured to generateradiant heat of approximately 500 W/m to approximately 1150 W/m duringuse.
 3337. The system of claim 3312, further comprising a support memberconfigured to support the insulated conductor, wherein the supportmember comprises orifices configured to provide fluid flow through thesupport member into the open wellbore during use.
 3338. The system ofclaim 3312, further comprising a support member configured to supportthe insulated conductor, wherein the support member comprises criticalflow orifices configured to provide a substantially constant amount offluid flow through the support member into the open wellbore during use.3339. The system of claim 3312, further comprising a tube coupled to theinsulated conductor, wherein the tube is configured to provide a flow offluid into the open wellbore during use.
 3340. The system of claim 3312,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configured to provide asubstantially constant amount of fluid flow through the support memberinto the open wellbore during use.
 3341. The system of claim 3312,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation.
 3342. The system of claim 3312, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3343. The system of claim 3312,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3344. The system of claim 3312, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3345. The system of claim 3312, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3346. The system of claim 3312, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3347. The system of claim 3312, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3348. The system of claim3312, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some of the hydrocarbonsin the selected section.
 3349. A system configurable to heat ahydrocarbon containing formation, comprising: an insulated conductorconfigurable to be disposed within an open wellbore in the formation,wherein the insulated conductor is further configurable to provideradiant heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from theinsulated conductor to a selected section of the formation during use.3350. The system of claim 3349, wherein the insulated conductor isfurther configurable to generate heat during application of anelectrical current to the insulated conductor during use.
 3351. Thesystem of claim 3349, further comprising a support member, wherein thesupport member is configurable to support the insulated conductor. 3352.The system of claim 3349, further comprising a support member and acentralizer, wherein the support member is configurable to support theinsulated conductor, and wherein the centralizer is configurable tomaintain a location of the insulated conductor on the support member.3353. The system of claim 3349, wherein the open wellbore comprises adiameter of at least approximately 5 cm.
 3354. The system of claim 3349,further comprising a lead-in conductor coupled to the insulatedconductor, wherein the lead-in conductor comprises a low resistanceconductor configurable to generate substantially no heat.
 3355. Thesystem of claim 3349, further comprising a lead-in conductor coupled tothe insulated conductor, wherein the lead-in conductor comprises arubber insulated conductor.
 3356. The system of claim 3349, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a copper wire.
 3357. The systemof claim 3349, further comprising a lead-in conductor coupled to theinsulated conductor with a cold pin transition conductor.
 3358. Thesystem of claim 3349, further comprising a lead-in conductor coupled tothe insulated conductor with a cold pin transition conductor, whereinthe cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3359. The system of claim 3349, whereinthe insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath.
 3360. The system of claim3349, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the conductor comprisesa copper-nickel alloy.
 3361. The system of claim 3349, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3362. The systemof claim 3349, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, wherein the conductorcomprises a copper-nickel alloy, and wherein the copper-nickel alloycomprises approximately 2% nickel by weight to approximately 6% nickelby weight.
 3363. The system of claim 3349, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprises athermally conductive material.
 3364. The system of claim 3349, whereinthe insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises magnesium oxide.
 3365. The system of claim3349, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3366. The systemof claim 3349, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3367. The system of claim 3349, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configurable to occupy porous spaces within themagnesium oxide.
 3368. The system of claim 3349, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material is disposedin a sheath, and wherein the sheath comprises a corrosion-resistantmaterial.
 3369. The system of claim 3349, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material is disposedin a sheath, and wherein the sheath comprises stainless steel.
 3370. Thesystem of claim 3349, further comprising two additional insulatedconductors, wherein the insulated conductor and the two additionalinsulated conductors are configurable in a 3-phase Y configuration.3371. The system of claim 3349, further comprising an additionalinsulated conductor, wherein the insulated conductor and the additionalinsulated conductor are coupled to a support member, and wherein theinsulated conductor and the additional insulated conductor areconfigurable in a series electrical configuration.
 3372. The system ofclaim 3349, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configurable in a parallelelectrical configuration.
 3373. The system of claim 3349, wherein theinsulated conductor is configurable to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3374. Thesystem of claim 3349, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisesorifices configurable to provide fluid flow through the support memberinto the open wellbore during use.
 3375. The system of claim 3349,further comprising a support member configurable to support theinsulated conductor, wherein the support member comprises critical floworifices configurable to provide a substantially constant amount offluid flow through the support member into the open wellbore during use.3376. The system of claim 3349, further comprising a tube coupled to theinsulated conductor, wherein the tube is configurable to provide a flowof fluid into the open wellbore during use.
 3377. The system of claim3349, further comprising a tube coupled to the first insulatedconductor, wherein the tube comprises critical flow orificesconfigurable to provide a substantially constant amount of fluid flowthrough the support member into the open wellbore during use.
 3378. Thesystem of claim 3349, further comprising an overburden casing coupled tothe open wellbore, wherein the overburden casing is disposed in anoverburden of the formation.
 3379. The system of claim 3349, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3380. The system of claim3349, further comprising an overburden casing coupled to the openwellbore, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing is further disposed incement.
 3381. The system of claim 3349, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3382. The system of claim 3349, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3383. The system of claim 3349, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3384. The system of claim 3349, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3385. The system ofclaim 3349, wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3386. The system of claim 3349, wherein thesystem is configured to heat a hydrocarbon containing formation, andwherein the system comprises: an insulated conductor disposed within anopen wellbore in the formation, wherein the insulated conductor isconfigured to provide radiant heat to at least a portion of theformation during use; and wherein the system is configured to allow heatto transfer from the insulated conductor to a selected section of theformation during use.
 3387. An in situ method for heating a hydrocarboncontaining formation, comprising: applying an electrical current to aninsulated conductor to provide radiant heat to at least a portion of theformation, wherein the insulated conductor is disposed within an openwellbore in the formation; and allowing the radiant heat to transferfrom the insulated conductor to a selected section of the formation.3388. The method of claim 3387, further comprising supporting theinsulated conductor on a support member.
 3389. The method of claim 3387,further comprising supporting the insulated conductor on a supportmember and maintaining a location of the insulated conductor on thesupport member with a centralizer.
 3390. The method of claim 3387,wherein the insulated conductor is coupled to two additional insulatedconductors, wherein the insulated conductor and the two insulatedconductors are disposed within the open wellbore, and wherein the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration.
 3391. The method of claim 3387, wherein an additionalinsulated conductor is disposed within the open wellbore.
 3392. Themethod of claim 3387, wherein an additional insulated conductor isdisposed within the open wellbore, and wherein the insulated conductorand the additional insulated conductor are electrically coupled in aseries configuration.
 3393. The method of claim 3387, wherein anadditional insulated conductor is disposed within the open wellbore, andwherein the insulated conductor and the additional insulated conductorare electrically coupled in a parallel configuration.
 3394. The methodof claim 3387, wherein the provided heat comprises approximately 500 W/mto approximately 1150 W/m.
 3395. The method of claim 3387, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3396. The method of claim 3387, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 7% nickel by weight toapproximately 12% nickel by weight.
 3397. The method of claim 3387,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 2% nickel by weight to approximately 6% nickel by weight.3398. The method of claim 3387, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3399. The method of claim 3387, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3400. The method of claim 3387, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the electrically insulating materialcomprises aluminum oxide and magnesium oxide.
 3401. The method of claim3387, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3402. Themethod of claim 3387, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3403. The method of claim3387, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3404. The method of claim 3387, further comprising supporting theinsulated conductor on a support member and flowing a fluid into theopen wellbore through an orifice in the support member.
 3405. The methodof claim 3387, further comprising supporting the insulated conductor ona support member and flowing a substantially constant amount of fluidinto the open wellbore through critical flow orifices in the supportmember.
 3406. The method of claim 3387, wherein a perforated tube isdisposed in the open wellbore proximate to the insulated conductor, themethod further comprising flowing a fluid into the open wellbore throughthe perforated tube.
 3407. The method of claim 3387, wherein a tube isdisposed in the open wellbore proximate to the insulated conductor, themethod further comprising flowing a substantially constant amount offluid into the open wellbore through critical flow orifices in the tube.3408. The method of claim 3387, further comprising supporting theinsulated conductor on a support member and flowing a corrosioninhibiting fluid into the open wellbore through an orifice in thesupport member.
 3409. The method of claim 3387, wherein a perforatedtube is disposed in the open wellbore proximate to the insulatedconductor, the method further comprising flowing a corrosion inhibitingfluid into the open wellbore through the perforated tube.
 3410. Themethod of claim 3387, further comprising determining a temperaturedistribution in the insulated conductor using an electromagnetic signalprovided to the insulated conductor.
 3411. The method of claim 3387,further comprising monitoring a leakage current of the insulatedconductor.
 3412. The method of claim 3387, further comprising monitoringthe applied electrical current.
 3413. The method of claim 3387, furthercomprising monitoring a voltage applied to the insulated conductor.3414. The method of claim 3387, further comprising monitoring atemperature in the insulated conductor with at least one thermocouple.3415. The method of claim 3387, further comprising electrically couplinga lead-in conductor to the insulated conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3416. The method of claim 3387, furthercomprising electrically coupling a lead-in conductor to the insulatedconductor using a cold pin transition conductor.
 3417. The method ofclaim 3387, further comprising electrically coupling a lead-in conductorto the insulated conductor using a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3418. The method of claim 3387, furthercomprising coupling an overburden casing to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation.3419. The method of claim 3387, further comprising coupling anoverburden casing to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing comprises steel.
 3420. The method of claim 3387, furthercomprising coupling an overburden casing to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3421. Themethod of claim 3387, further comprising coupling an overburden casingto the open wellbore, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the open wellbore.
 3422. Themethod of claim 3387, further comprising coupling an overburden casingto the open wellbore, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the method further comprisesinhibiting a flow of fluid between the open wellbore and the overburdencasing with a packing material.
 3423. The method of claim 3387, furthercomprising heating at least the portion of the formation to pyrolyze atleast some hydrocarbons within the formation.
 3424. An in situ methodfor heating a hydrocarbon containing formation, comprising: applying anelectrical current to an insulated conductor to provide heat to at leasta portion of the formation, wherein the insulated conductor is disposedwithin an opening in the formation; and allowing the heat to transferfrom the insulated conductor to a section of the formation.
 3425. Themethod of claim 3424, further comprising supporting the insulatedconductor on a support member.
 3426. The method of claim 3424, furthercomprising supporting the insulated conductor on a support member andmaintaining a location of the first insulated conductor on the supportmember with a centralizer.
 3427. The method of claim 3424, wherein theinsulated conductor is coupled to two additional insulated conductors,wherein the insulated conductor and the two insulated conductors aredisposed within the opening, and wherein the three insulated conductorsare electrically coupled in a 3-phase Y configuration.
 3428. The methodof claim 3424, wherein an additional insulated conductor is disposedwithin the opening.
 3429. The method of claim 3424, wherein anadditional insulated conductor is disposed within the opening, andwherein the insulated conductor and the additional insulated conductorare electrically coupled in a series configuration.
 3430. The method ofclaim 3424, wherein an additional insulated conductor is disposed withinthe opening, and wherein the insulated conductor and the additionalinsulated conductor are electrically coupled in a parallelconfiguration.
 3431. The method of claim 3424, wherein the provided heatcomprises approximately 500 W/m to approximately 1150 W/m.
 3432. Themethod of claim 3424, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3433. The method of claim3424, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3434. The method of claim 3424, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3435. The method of claim 3424,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises magnesium oxide.
 3436. The method of claim3424, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3437. The methodof claim 3424, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3438. The method of claim 3424, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configured to occupy porous spaces within themagnesium oxide.
 3439. The method of claim 3424, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the insulating material is disposed in a sheath, andwherein the sheath comprises a corrosion-resistant material.
 3440. Themethod of claim 3424, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3441. The method of claim 3424, furthercomprising supporting the insulated conductor on a support member andflowing a fluid into the opening through an orifice in the supportmember.
 3442. The method of claim 3424, further comprising supportingthe insulated conductor on a support member and flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the support member.
 3443. The method of claim 3424, wherein aperforated tube is disposed in the opening proximate to the insulatedconductor, the method further comprising flowing a fluid into theopening through the perforated tube.
 3444. The method of claim 3424,wherein a tube is disposed in the opening proximate to the insulatedconductor, the method further comprising flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the tube.
 3445. The method of claim 3424, further comprisingsupporting the insulated conductor on a support member and flowing acorrosion inhibiting fluid into the opening through an orifice in thesupport member.
 3446. The method of claim 3424, wherein a perforatedtube is disposed in the opening proximate to the insulated conductor,the method further comprising flowing a corrosion inhibiting fluid intothe opening through the perforated tube.
 3447. The method of claim 3424,further comprising determining a temperature distribution in theinsulated conductor using an electromagnetic signal provided to theinsulated conductor.
 3448. The method of claim 3424, further comprisingmonitoring a leakage current of the insulated conductor.
 3449. Themethod of claim 3424, further comprising monitoring the appliedelectrical current.
 3450. The method of claim 3424, further comprisingmonitoring a voltage applied to the insulated conductor.
 3451. Themethod of claim 3424, further comprising monitoring a temperature in theinsulated conductor with at least one thermocouple.
 3452. The method ofclaim 3424, further comprising electrically coupling a lead-in conductorto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3453. The method of claim 3424, further comprising electrically couplinga lead-in conductor to the insulated conductor using a cold pintransition conductor.
 3454. The method of claim 3424, further comprisingelectrically coupling a lead-in conductor to the insulated conductorusing a cold pin transition conductor, wherein the cold pin transitionconductor comprises a substantially low resistance insulated conductor.3455. The method of claim 3424, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3456. The method of claim3424, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3457. Themethod of claim 3424, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3458. The method of claim 3424, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3459. The method of claim 3424, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3460. Themethod of claim 3424, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some hydrocarbonswithin the formation.
 3461. A system configured to heat a hydrocarboncontaining formation, comprising: an insulated conductor disposed withinan opening in the formation, wherein the insulated conductor isconfigured to provide heat to at least a portion of the formation duringuse, wherein the insulated conductor comprises a copper-nickel alloy,and wherein the copper-nickel alloy comprises approximately 7% nickel byweight to approximately 12% nickel by weight; and wherein the system isconfigured to allow heat to transfer from the insulated conductor to aselected section of the formation during use.
 3462. The system of claim3461, wherein the insulated conductor is further configured to generateheat during application of an electrical current to the insulatedconductor during use.
 3463. The system of claim 3461, further comprisinga support member, wherein the support member is configured to supportthe insulated conductor.
 3464. The system of claim 3461, furthercomprising a support member and a centralizer, wherein the supportmember is configured to support the insulated conductor, and wherein thecentralizer is configured to maintain a location of the insulatedconductor on the support member.
 3465. The system of claim 3461, whereinthe opening comprises a diameter of at least approximately 5 cm. 3466.The system of claim 3461, further comprising a lead-in conductor coupledto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3467. The system of claim 3461, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a rubber insulated conductor.
 3468. The system of claim 3461,further comprising a lead-in conductor coupled to the insulatedconductor, wherein the lead-in conductor comprises a copper wire. 3469.The system of claim 3461, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor. 3470.The system of claim 3461, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor, whereinthe cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3471. The system of claim 3461, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprises athermally conductive material.
 3472. The system of claim 3461, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprisesmagnesium oxide.
 3473. The system of claim 3461, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3474. The system of claim 3461, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3475. The system of claim 3461, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configured to occupy porous spaces within themagnesium oxide.
 3476. The system of claim 3461, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material is disposed in a sheath,and wherein the sheath comprises a corrosion-resistant material. 3477.The system of claim 3461, wherein the copper-nickel alloy is disposed inan electrically insulating material, wherein the electrically insulatingmaterial is disposed in a sheath, and wherein the sheath comprisesstainless steel.
 3478. The system of claim 3461, further comprising twoadditional insulated conductors, wherein the insulated conductor and thetwo additional insulated conductors are configured in a 3-phase Yconfiguration.
 3479. The system of claim 3461, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configured in a series electrical configuration.
 3480. The system ofclaim 3461, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configured in a parallelelectrical configuration.
 3481. The system of claim 3461, wherein theinsulated conductor is configured to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3482. Thesystem of claim 3461, further comprising a support member configured tosupport the insulated conductor, wherein the support member comprisesorifices configured to provide fluid flow through the support memberinto the opening during use.
 3483. The system of claim 3461, furthercomprising a support member configured to support the insulatedconductor, wherein the support member comprises critical flow orificesconfigured to provide a substantially constant amount of fluid flowthrough the support member into the opening during use.
 3484. The systemof claim 3461, further comprising a tube coupled to the insulatedconductor, wherein the tube is configured to provide a flow of fluidinto the opening during use.
 3485. The system of claim 3461, furthercomprising a tube coupled to the insulated conductor, wherein the tubecomprises critical flow orifices configured to provide a substantiallyconstant amount of fluid flow through the support member into theopening during use.
 3486. The system of claim 3461, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3487. The systemof claim 3461, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3488.The system of claim 3461, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3489. The system of claim 3461, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3490. The system of claim 3461, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3491. The system of claim 3461, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3492. The system of claim 3461, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, the system further comprising a wellheadcoupled to the overburden casing and a lead-in conductor coupled to theinsulated conductor, wherein the wellhead is disposed external to theoverburden, wherein the wellhead comprises at least one sealing flange,and wherein at least the one sealing flange is configured to couple tothe lead-in conductor.
 3493. The system of claim 3461, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.3494. A system configurable to heat a hydrocarbon containing formation,comprising: an insulated conductor configurable to be disposed within anopening in the formation, wherein the insulated conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use, wherein the insulated conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight; and wherein thesystem is configurable to allow heat to transfer from the insulatedconductor to a selected section of the formation during use.
 3495. Thesystem of claim 3494, wherein the insulated conductor is furtherconfigurable to generate heat during application of an electricalcurrent to the insulated conductor during use.
 3496. The system of claim3494, further comprising a support member, wherein the support member isconfigurable to support the insulated conductor.
 3497. The system ofclaim 3494, further comprising a support member and a centralizer,wherein the support member is configurable to support the insulatedconductor, and wherein the centralizer is configurable to maintain alocation of the insulated conductor on the support member.
 3498. Thesystem of claim 3494, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3499. The system of claim 3494, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a low resistance conductorconfigurable to generate substantially no heat.
 3500. The system ofclaim 3494, further comprising a lead-in conductor coupled to theinsulated conductor, wherein the lead-in conductor comprises a rubberinsulated conductor.
 3501. The system of claim 3494, further comprisinga lead-in conductor coupled to the insulated conductor, wherein thelead-in conductor comprises a copper wire.
 3502. The system of claim3494, further comprising a lead-in conductor coupled to the insulatedconductor with a cold pin transition conductor.
 3503. The system ofclaim 3494, further comprising a lead-in conductor coupled to theinsulated conductor with a cold pin transition conductor, wherein thecold pin transition conductor comprises a substantially low resistanceinsulated conductor.
 3504. The system of claim 3494, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises a thermallyconductive material.
 3505. The system of claim 3494, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3506. The system of claim 3494, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3507. The system of claim 3494, wherein the copper-nickel alloy isdisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3508. The system of claim 3494, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, wherein themagnesium oxide comprises grain particles, and wherein the grainparticles are configurable to occupy porous spaces within the magnesiumoxide.
 3509. The system of claim 3494, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material is disposed in a sheath, and whereinthe sheath comprises a corrosion-resistant material.
 3510. The system ofclaim 3494, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the electrically insulatingmaterial is disposed in a sheath, and wherein the sheath comprisesstainless steel.
 3511. The system of claim 3494, further comprising twoadditional insulated conductors, wherein the insulated conductor and thetwo additional insulated conductors are configurable in a 3-phase Yconfiguration.
 3512. The system of claim 3494, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configurable in a series electrical configuration.
 3513. The systemof claim 3494, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configurable in a parallelelectrical configuration.
 3514. The system of claim 3494, wherein theinsulated conductor is configurable to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3515. Thesystem of claim 3494, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisesorifices configurable to provide fluid flow through the support memberinto the open wellbore during use.
 3516. The system of claim 3494,further comprising a support member configurable to support theinsulated conductor, wherein the support member comprises critical floworifices configurable to provide a substantially constant amount offluid flow through the support member into the opening during use. 3517.The system of claim 3494, further comprising a tube coupled to theinsulated conductor, wherein the tube is configurable to provide a flowof fluid into the opening during use.
 3518. The system of claim 3494,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configurable to provide asubstantially constant amount of fluid flow through the support memberinto the opening during use.
 3519. The system of claim 3494, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3520.The system of claim 3494, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3521. The system of claim 3494, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3522. The system of claim 3494, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3523. The system of claim 3494, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3524. The system of claim 3494, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3525. The system of claim 3494, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, the system further comprising a wellheadcoupled to the overburden casing and a lead-in conductor coupled to theinsulated conductor, wherein the wellhead is disposed external to theoverburden, wherein the wellhead comprises at least one sealing flange,and wherein at least the one sealing flange is configurable to couple tothe lead-in conductor.
 3526. The system of claim 3494, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.3527. The system of claim 3494, wherein the system is configured to heata hydrocarbon containing formation, and wherein the system comprises: aninsulated conductor disposed within an opening in the formation, whereinthe insulated conductor is configured to provide heat to at least aportion of the formation during use, wherein the insulated conductorcomprises a copper-nickel alloy, and wherein the copper-nickel alloycomprises approximately 7% nickel by weight to approximately 12% nickelby weight; and wherein the system is configured to allow heat totransfer from the insulated conductor to a selected section of theformation during use.
 3528. An in situ method for heating a hydrocarboncontaining formation, comprising: applying an electrical current to aninsulated conductor to provide heat to at least a portion of theformation, wherein the insulated conductor is disposed within an openingin the formation, and wherein the insulated conductor comprises acopper-nickel alloy of approximately 7% nickel by weight toapproximately 12% nickel by weight; and allowing the heat to transferfrom the insulated conductor to a selected section of the formation.3529. The method of claim 3528, further comprising supporting theinsulated conductor on a support member.
 3530. The method of claim 3528,further comprising supporting the insulated conductor on a supportmember and maintaining a location of the first insulated conductor onthe support member with a centralizer.
 3531. The method of claim 3528,wherein the insulated conductor is coupled to two additional insulatedconductors, wherein the insulated conductor and the two insulatedconductors are disposed within the opening, and wherein the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration.
 3532. The method of claim 3528, wherein an additionalinsulated conductor is disposed within the opening.
 3533. The method ofclaim 3528, wherein an additional insulated conductor is disposed withinthe opening, and wherein the insulated conductor and the additionalinsulated conductor are electrically coupled in a series configuration.3534. The method of claim 3528, wherein an additional insulatedconductor is disposed within the opening, and wherein the insulatedconductor and the additional insulated conductor are electricallycoupled in a parallel configuration.
 3535. The method of claim 3528,wherein the provided heat comprises approximately 500 W/m toapproximately 1150 W/m.
 3536. The method of claim 3528, wherein thecopper-nickel alloy is disposed in an electrically insulating material.3537. The method of claim 3528, wherein the copper-nickel alloy isdisposed in an electrically insulating material, and wherein theelectrically insulating material comprises magnesium oxide.
 3538. Themethod of claim 3528, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3539. The methodof claim 3528, wherein the copper-nickel alloy is disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises aluminum oxide and magnesium oxide. 3540.The method of claim 3528, wherein the copper-nickel alloy is disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3541. Themethod of claim 3528, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3542. The method of claim 3528, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, wherein the insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3543. The method of claim3528, further comprising supporting the insulated conductor on a supportmember and flowing a fluid into the opening through an orifice in thesupport member.
 3544. The method of claim 3528, further comprisingsupporting the insulated conductor on a support member and flowing asubstantially constant amount of fluid into the opening through criticalflow orifices in the support member.
 3545. The method of claim 3528,wherein a perforated tube is disposed in the opening proximate to theinsulated conductor, the method further comprising flowing a fluid intothe opening through the perforated tube.
 3546. The method of claim 3528,wherein a tube is disposed in the opening proximate to the insulatedconductor, the method further comprising flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the tube.
 3547. The method of claim 3528, further comprisingsupporting the insulated conductor on a support member and flowing acorrosion inhibiting fluid into the opening through an orifice in thesupport member.
 3548. The method of claim 3528, wherein a perforatedtube is disposed in the opening proximate to the insulated conductor,the method further comprising flowing a corrosion inhibiting fluid intothe opening through the perforated tube.
 3549. The method of claim 3528,further comprising determining a temperature distribution in theinsulated conductor using an electromagnetic signal provided to theinsulated conductor.
 3550. The method of claim 3528, further comprisingmonitoring a leakage current of the insulated conductor.
 3551. Themethod of claim 3528, further comprising monitoring the appliedelectrical current.
 3552. The method of claim 3528, further comprisingmonitoring a voltage applied to the insulated conductor.
 3553. Themethod of claim 3528, further comprising monitoring a temperature in theinsulated conductor with at least one thermocouple.
 3554. The method ofclaim 3528, further comprising electrically coupling a lead-in conductorto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3555. The method of claim 3528, further comprising electrically couplinga lead-in conductor to the insulated conductor using a cold pintransition conductor.
 3556. The method of claim 3528, further comprisingelectrically coupling a lead-in conductor to the insulated conductorusing a cold pin transition conductor, wherein the cold pin transitionconductor comprises a substantially low resistance insulated conductor.3557. The method of claim 3528, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3558. The method of claim3528, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3559. Themethod of claim 3528, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3560. The method of claim 3528, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3561. The method of claim 3528, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3562. Themethod of claim 3528, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some hydrocarbonswithin the formation.
 3563. A system configured to heat a hydrocarboncontaining formation, comprising: at least three insulated conductorsdisposed within an opening in the formation, wherein at least the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration, and wherein at least the three insulated conductors areconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromat least the three insulated conductors to a selected section of theformation during use.
 3564. The system of claim 3563, wherein at leastthe three insulated conductors are further configured to generate heatduring application of an electrical current to at least the threeinsulated conductors during use.
 3565. The system of claim 3563, furthercomprising a support member, wherein the support member is configured tosupport at least the three insulated conductors.
 3566. The system ofclaim 3563, further comprising a support member and a centralizer,wherein the support member is configured to support at least the threeinsulated conductors, and wherein the centralizer is configured tomaintain a location of at least the three insulated conductors on thesupport member.
 3567. The system of claim 3563, wherein the openingcomprises a diameter of at least approximately 5 cm.
 3568. The system ofclaim 3563, further comprising at least one lead-in conductor coupled toat least the three insulated conductors, wherein at least the onelead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3569. The system of claim 3563, furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors, wherein at least the one lead-in conductorcomprises a rubber insulated conductor.
 3570. The system of claim 3563,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a copper wire.
 3571. The system of claim 3563,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors with a cold pin transition conductor.3572. The system of claim 3563, further comprising at least one lead-inconductor coupled to at least the three insulated conductors with a coldpin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3573. Thesystem of claim 3563, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material is disposed in asheath.
 3574. The system of claim 3563, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3575. The system of claim 3563, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3576. The systemof claim 3563, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3577. The system of claim 3563, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3578. Thesystem of claim 3563, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3579. The system of claim 3563, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3580. The system of claim3563, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3581. The system of claim 3563, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configured to occupy porous spaceswithin the magnesium oxide.
 3582. The system of claim 3563, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3583. The system of claim3563, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3584. The system of claim3563, wherein at least the three insulated conductors are configured togenerate radiant heat of approximately 500 W/m to approximately 1150 W/mof at least the three insulated conductors during use.
 3585. The systemof claim 3563, further comprising a support member configured to supportat least the three insulated conductors, wherein the support membercomprises orifices configured to provide fluid flow through the supportmember into the opening during use.
 3586. The system of claim 3563,further comprising a support member configured to support at least thethree insulated conductors, wherein the support member comprisescritical flow orifices configured to provide a substantially constantamount of fluid flow through the support member into the opening duringuse.
 3587. The system of claim 3563, further comprising a tube coupledto at least the three insulated conductors, wherein the tube isconfigured to provide a flow of fluid into the opening during use. 3588.The system of claim 3563, further comprising a tube coupled to at leastthe three insulated conductors, wherein the tube comprises critical floworifices configured to provide a substantially constant amount of fluidflow through the support member into the opening during use.
 3589. Thesystem of claim 3563, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3590. The system of claim 3563, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3591. The system of claim 3563,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3592. Thesystem of claim 3563, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3593. The system ofclaim 3563, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3594. The system of claim3563, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3595. The system of claim 3563, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3596. The system of claim3563, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some hydrocarbons in theselected section.
 3597. A system configurable to heat a hydrocarboncontaining formation, comprising: at least three insulated conductorsconfigurable to be disposed within an opening in the formation, whereinat least the three insulated conductors are electrically coupled in a3-phase Y configuration, and wherein at least the three insulatedconductors are further configurable to provide heat to at least aportion of the formation during use; and wherein the system isconfigurable to allow heat to transfer from at least the three insulatedconductors to a selected section of the formation during use.
 3598. Thesystem of claim 3597, wherein at least the three insulated conductorsare further configurable to generate heat during application of anelectrical current to at least the three insulated conductors duringuse.
 3599. The system of claim 3597, further comprising a supportmember, wherein the support member is configurable to support at leastthe three insulated conductors.
 3600. The system of claim 3597, furthercomprising a support member and a centralizer, wherein the supportmember is configurable to support at least the three insulatedconductors, and wherein the centralizer is configurable to maintain alocation of at least the three insulated conductors on the supportmember.
 3601. The system of claim 3597, wherein the opening comprises adiameter of at least approximately 5 cm.
 3602. The system of claim 3597,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a low resistance conductor configurable to generatesubstantially no heat.
 3603. The system of claim 3597, furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors, wherein at least the one lead-in conductorcomprises a rubber insulated conductor.
 3604. The system of claim 3597,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a copper wire.
 3605. The system of claim 3597,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors with a cold pin transition conductor.3606. The system of claim 3597, further comprising at least one lead-inconductor coupled to at least the three insulated conductors with a coldpin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3607. Thesystem of claim 3597, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material is disposed in asheath.
 3608. The system of claim 3597, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3609. The system of claim 3597, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3610. The systemof claim 3597, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3611. The system of claim 3597, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3612. Thesystem of claim 3597, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3613. The system of claim 3597, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3614. The system of claim3597, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3615. The system of claim 3597, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configurable to occupy porous spaceswithin the magnesium oxide.
 3616. The system of claim 3597, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3617. The system of claim3597, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3618. The system of claim3597, wherein at least the three insulated conductors are configurableto generate radiant heat of approximately 500 W/m to approximately 1150W/m during use.
 3619. The system of claim 3597, further comprising asupport member configurable to support at least the three insulatedconductors, wherein the support member comprises orifices configurableto provide fluid flow through the support member into the opening duringuse.
 3620. The system of claim 3597, further comprising a support memberconfigurable to support at least the three insulated conductors, whereinthe support member comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3621. The system of claim3597, further comprising a tube coupled to at least the three insulatedconductors, wherein the tube is configurable to provide a flow of fluidinto the opening during use.
 3622. The system of claim 3597, furthercomprising a tube coupled to at least the three insulated conductors,wherein the tube comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3623. The system of claim3597, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3624. The system of claim 3597, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3625. The system of claim 3597,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3626. Thesystem of claim 3597, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3627. The system ofclaim 3597, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3628. The system of claim3597, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3629. The system of claim 3597, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3630. The system ofclaim 3597, wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3631. The system of claim 3597, wherein thesystem is configured to heat a hydrocarbon containing formation, andwherein the system comprises: at least three insulated conductorsdisposed within an opening in the formation, wherein at least the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration, and wherein at least the three insulated conductors areconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromat least the three insulated conductors to a selected section of theformation during use.
 3632. An in situ method for heating a hydrocarboncontaining formation, comprising: applying an electrical current to atleast three insulated conductors to provide heat to at least a portionof the formation, wherein at least the three insulated conductors aredisposed within an opening in the formation; and allowing the heat totransfer from at least the three insulated conductors to a selectedsection of the formation.
 3633. The method of claim 3632, furthercomprising supporting at least the three insulated conductors on asupport member.
 3634. The method of claim 3632, further comprisingsupporting at least the three insulated conductors on a support memberand maintaining a location of at least the three insulated conductors onthe support member with a centralizer.
 3635. The method of claim 3632,wherein the provided heat comprises approximately 500 W/m toapproximately 1150 W/m.
 3636. The method of claim 3632, wherein at leastthe three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the conductor comprises acopper-nickel alloy.
 3637. The method of claim 3632, wherein at leastthe three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3638. The method of claim 3632, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the conductor comprises a copper-nickel alloy, andwherein the copper-nickel alloy comprises approximately 2% nickel byweight to approximately 6% nickel by weight.
 3639. The method of claim3632, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3640.The method of claim 3632, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, and wherein the magnesium oxide comprises a thicknessof at least approximately 1 mm.
 3641. The method of claim 3632, whereinat least the three insulated conductors comprise a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material comprises aluminum oxide and magnesium oxide. 3642.The method of claim 3632, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configured to occupy porous spaceswithin the magnesium oxide.
 3643. The method of claim 3632, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3644. The method of claim 3632, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3645. The method of claim 3632, further comprising supporting at leastthe three insulated conductors on a support member and flowing a fluidinto the opening through an orifice in the support member.
 3646. Themethod of claim 3632, further comprising supporting at least the threeinsulated conductors on a support member and flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the support member.
 3647. The method of claim 3632, wherein aperforated tube is disposed in the opening proximate to at least thethree insulated conductors, the method further comprising flowing afluid into the opening through the perforated tube.
 3648. The method ofclaim 3632, wherein a tube is disposed in the opening proximate to atleast the three insulated conductors, the method further comprisingflowing a substantially constant amount of fluid into the openingthrough critical flow orifices in the tube.
 3649. The method of claim3632, further comprising supporting at least the three insulatedconductors on a support member and flowing a corrosion inhibiting fluidinto the opening through an orifice in the support member.
 3650. Themethod of claim 3632, wherein a perforated tube is disposed in theopening proximate to at least the three insulated conductors, the methodfurther comprising flowing a corrosion inhibiting fluid into the openingthrough the perforated tube.
 3651. The method of claim 3632, furthercomprising determining a temperature distribution in at least the threeinsulated conductors using an electromagnetic signal provided to theinsulated conductor.
 3652. The method of claim 3632, further comprisingmonitoring a leakage current of at least the three insulated conductors.3653. The method of claim 3632, further comprising monitoring theapplied electrical current.
 3654. The method of claim 3632, furthercomprising monitoring a voltage applied to at least the three insulatedconductors.
 3655. The method of claim 3632, further comprisingmonitoring a temperature in at least the three insulated conductors withat least one thermocouple.
 3656. The method of claim 3632, furthercomprising electrically coupling a lead-in conductor to at least thethree insulated conductors, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3657. The method of claim 3632, further comprising electrically couplinga lead-in conductor to at least the three insulated conductors using acold pin transition conductor.
 3658. The method of claim 3632, furthercomprising electrically coupling a lead-in conductor to at least thethree insulated conductors using a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3659. The method of claim 3632, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3660.The method of claim 3632, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3661. The method of claim 3632, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3662. The method of claim 3632,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3663. The method of claim 3632, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3664. Themethod of claim 3632, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some of thehydrocarbons within the formation.
 3665. A system configured to heat ahydrocarbon containing formation, comprising: a first conductor disposedin a first conduit, wherein the first conduit is disposed within anopening in the formation, and wherein the first conductor is configuredto provide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst conductor to a section of the formation during use.
 3666. Thesystem of claim 3665, wherein the first conductor is further configuredto generate heat during application of an electrical current to thefirst conductor.
 3667. The system of claim 3665, wherein the firstconductor comprises a pipe.
 3668. The system of claim 3665, wherein thefirst conductor comprises stainless steel.
 3669. The system of claim3665, wherein the first conduit comprises stainless steel.
 3670. Thesystem of claim 3665, further comprising a centralizer configured tomaintain a location of the first conductor within the first conduit.3671. The system of claim 3665, further comprising a centralizerconfigured to maintain a location of the first conductor within thefirst conduit, wherein the centralizer comprises ceramic material. 3672.The system of claim 3665, further comprising a centralizer configured tomaintain a location of the first conductor within the first conduit,wherein the centralizer comprises ceramic material and stainless steel.3673. The system of claim 3665, wherein the opening comprises a diameterof at least approximately 5 cm.
 3674. The system of claim 3665, furthercomprising a lead-in conductor coupled to the first conductor, whereinthe lead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3675. The system of claim 3665, furthercomprising a lead-in conductor coupled to the first conductor, whereinthe lead-in conductor comprises copper.
 3676. The system of claim 3665,further comprising a sliding electrical connector coupled to the firstconductor.
 3677. The system of claim 3665, further comprising a slidingelectrical connector coupled to the first conductor, wherein the slidingelectrical connector is further coupled to the first conduit.
 3678. Thesystem of claim 3665, further comprising a sliding electrical connectorcoupled to the first conductor, wherein the sliding electrical connectoris further coupled to the first conduit, and wherein the slidingelectrical connector is configured to complete an electrical circuitwith the first conductor and the first conduit.
 3679. The system ofclaim 3665, further comprising a second conductor disposed within thefirst conduit and at least one sliding electrical connector coupled tothe first conductor and the second conductor, wherein at least the onesliding electrical connector is configured to generate less heat thanthe first conductor or the second conductor during use.
 3680. The systemof claim 3665, wherein the first conduit comprises a first section and asecond section, wherein a thickness of the first section is greater thana thickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3681. The system of claim 3665, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configured to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3682.The system of claim 3665, further comprising a thermally conductivefluid disposed within the first conduit.
 3683. The system of claim 3665,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3684. The system of claim 3665, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configured tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3685. The system of claim 3665, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configured to remove vapor produced from at least the heatedportion of the formation such that a pressure balance is maintainedbetween the first conduit and the opening to substantially inhibitdeformation of the first conduit during use.
 3686. The system of claim3665, wherein the first conductor is further configured to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3687. The system of claim 3665, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein the first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configured to operate in a 3-phase Yconfiguration during use.
 3688. The system of claim 3665, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3689. The system of claim 3665, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3690. The system of claim3665, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3691. The system of claim 3665, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3692. The system of claim 3665,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3693. Thesystem of claim 3665, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3694. The system ofclaim 3665, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3695. The system ofclaim 3665, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3696. The system of claim3665, further comprising an overburden casing coupled to the opening anda substantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3697. Thesystem of claim 3665, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3698. The system of claim 3665, wherein the heated section of theformation is substantially pyrolyzed.
 3699. A system configurable toheat a hydrocarbon containing formation, comprising: a first conductorconfigurable to be disposed in a first conduit, wherein the firstconduit is configurable to be disposed within an opening in theformation, and wherein the first conductor is further configurable toprovide heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from thefirst conductor to a section of the formation during use.
 3700. Thesystem of claim 3699, wherein the first conductor is furtherconfigurable to generate heat during application of an electricalcurrent to the first conductor.
 3701. The system of claim 3699, whereinthe first conductor comprises a pipe.
 3702. The system of claim 3699,wherein the first conductor comprises stainless steel.
 3703. The systemof claim 3699, wherein the first conduit comprises stainless steel.3704. The system of claim 3699, further comprising a centralizerconfigurable to maintain a location of the first conductor within thefirst conduit.
 3705. The system of claim 3699, further comprising acentralizer configurable to maintain a location of the first conductorwithin the first conduit, wherein the centralizer comprises ceramicmaterial.
 3706. The system of claim 3699, further comprising acentralizer configurable to maintain a location of the first conductorwithin the first conduit, wherein the centralizer comprises ceramicmaterial and stainless steel.
 3707. The system of claim 3699, whereinthe opening comprises a diameter of at least approximately 5 cm. 3708.The system of claim 3699, further comprising a lead-in conductor coupledto the first conductor, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.3709. The system of claim 3699, further comprising a lead-in conductorcoupled to the first conductor, wherein the lead-in conductor comprisescopper.
 3710. The system of claim 3699, further comprising a slidingelectrical connector coupled to the first conductor.
 3711. The system ofclaim 3699, further comprising a sliding electrical connector coupled tothe first conductor, wherein the sliding electrical connector is furthercoupled to the first conduit.
 3712. The system of claim 3699, furthercomprising a sliding electrical connector coupled to the firstconductor, wherein the sliding electrical connector is further coupledto the first conduit, and wherein the sliding electrical connector isconfigurable to complete an electrical circuit with the first conductorand the first conduit.
 3713. The system of claim 3699, furthercomprising a second conductor disposed within the first conduit and atleast one sliding electrical connector coupled to the first conductorand the second conductor, wherein at least the one sliding electricalconnector is configurable to generate less heat than the first conductoror the second conductor during use.
 3714. The system of claim 3699,wherein the first conduit comprises a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3715. The system of claim 3699, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3716.The system of claim 3699, further comprising a thermally conductivefluid disposed within the first conduit.
 3717. The system of claim 3699,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3718. The system of claim 3699, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configurable tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3719. The system of claim 3699, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configurable to remove vapor produced from at least theheated portion of the formation such that a pressure balance ismaintained between the first conduit and the opening to substantiallyinhibit deformation of the first conduit during use.
 3720. The system ofclaim 3699, wherein the first conductor is further configurable togenerate radiant heat of approximately 650 W/m to approximately 1650 W/mduring use.
 3721. The system of claim 3699, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein the first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configurable to operate in a 3-phase Yconfiguration during use.
 3722. The system of claim 3699, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3723. The system of claim 3699, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3724. The system of claim3699, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3725. The system of claim 3699, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3726. The system of claim 3699,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3727. Thesystem of claim 3699, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3728. The system ofclaim 3699, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3729. The system ofclaim 3699, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3730. The system of claim3699, further comprising an overburden casing coupled to the opening anda substantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3731. Thesystem of claim 3699, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3732. The system of claim 3699, wherein the heated section of theformation is substantially pyrolyzed.
 3733. The system of claim 3699,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a first conductor disposedin a first conduit, wherein the first conduit is disposed within anopening in the formation, and wherein the first conductor is configuredto provide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst conductor to a section of the formation during use.
 3734. An insitu method for heating a hydrocarbon containing formation, comprising:applying an electrical current to a first conductor to provide heat toat least a portion of the formation, wherein the first conductor isdisposed in a first conduit, and wherein the first conduit is disposedwithin an opening in the formation; and allowing the heat to transferfrom the first conductor to a section of the formation.
 3735. The methodof claim 3734, wherein the first conductor comprises a pipe.
 3736. Themethod of claim 3734, wherein the first conductor comprises stainlesssteel.
 3737. The method of claim 3734, wherein the first conduitcomprises stainless steel.
 3738. The method of claim 3734, furthercomprising maintaining a location of the first conductor in the firstconduit with a centralizer.
 3739. The method of claim 3734, furthercomprising maintaining a location of the first conductor in the firstconduit with a centralizer, wherein the centralizer comprises ceramicmaterial.
 3740. The method of claim 3734, further comprising maintaininga location of the first conductor in the first conduit with acentralizer, wherein the centralizer comprises ceramic material andstainless steel.
 3741. The method of claim 3734, further comprisingcoupling a sliding electrical connector to the first conductor. 3742.The method of claim 3734, further comprising electrically coupling asliding electrical connector to the first conductor and the firstconduit, wherein the first conduit comprises an electrical leadconfigured to complete an electrical circuit with the first conductor.3743. The method of claim 3734, further comprising coupling a slidingelectrical connector to the first conductor and the first conduit,wherein the first conduit comprises an electrical lead configured tocomplete an electrical circuit with the first conductor, and wherein thegenerated heat comprises approximately 20 percent generated by the firstconduit.
 3744. The method of claim 3734, wherein the provided heatcomprises approximately 650 W/m to approximately 1650 W/m.
 3745. Themethod of claim 3734, further comprising determining a temperaturedistribution in the first conduit using an electromagnetic signalprovided to the conduit.
 3746. The method of claim 3734, furthercomprising monitoring the applied electrical current.
 3747. The methodof claim 3734, further comprising monitoring a voltage applied to thefirst conductor.
 3748. The method of claim 3734, further comprisingmonitoring a temperature in the conduit with at least one thermocouple.3749. The method of claim 3734, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3750. The method of claim3734, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3751. Themethod of claim 3734, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3752. The method of claim 3734, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3753. The method of claim 3734, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3754. Themethod of claim 3734, further comprising coupling an overburden casingto the opening, wherein a substantially low resistance conductor isdisposed within the overburden casing, and wherein the substantially lowresistance conductor is electrically coupled to the first conductor.3755. The method of claim 3734, further comprising coupling anoverburden casing to the opening, wherein a substantially low resistanceconductor is disposed within the overburden casing, wherein thesubstantially low resistance conductor is electrically coupled to thefirst conductor, and wherein the substantially low resistance conductorcomprises carbon steel.
 3756. The method of claim 3734, furthercomprising coupling an overburden casing to the opening, wherein asubstantially low resistance conductor is disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein the methodfurther comprises maintaining a location of the substantially lowresistance conductor in the overburden casing with a centralizersupport.
 3757. The method of claim 3734, further comprising electricallycoupling a lead-in conductor to the first conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3758. The method of claim 3734, furthercomprising electrically coupling a lead-in conductor to the firstconductor, wherein the lead-in conductor comprises copper.
 3759. Themethod of claim 3734, further comprising maintaining a sufficientpressure between the first conduit and the formation to substantiallyinhibit deformation of the first conduit.
 3760. The method of claim3734, further comprising providing a thermally conductive fluid withinthe first conduit.
 3761. The method of claim 3734, further comprisingproviding a thermally conductive fluid within the first conduit, whereinthe thermally conductive fluid comprises helium.
 3762. The method ofclaim 3734, further comprising inhibiting arcing between the firstconductor and the first conduit with a fluid disposed within the firstconduit.
 3763. The method of claim 3734, further comprising removing avapor from the opening using a perforated tube disposed proximate to thefirst conduit in the opening to control a pressure in the opening. 3764.The method of claim 3734, further comprising flowing a corrosioninhibiting fluid through a perforated tube disposed proximate to thefirst conduit in the opening.
 3765. The method of claim 3734, wherein asecond conductor is disposed within the first conduit, wherein thesecond conductor is electrically coupled to the first conductor to forman electrical circuit.
 3766. The method of claim 3734, wherein a secondconductor is disposed within the first conduit, wherein the secondconductor is electrically coupled to the first conductor with aconnector.
 3767. The method of claim 3734, wherein a second conductor isdisposed within a second conduit and a third conductor is disposedwithin a third conduit, wherein the second conduit and the third conduitare disposed in different openings of the formation, wherein the firstconductor is electrically coupled to the second conductor and the thirdconductor, and wherein the first, second, and third conductors areconfigured to operate in a 3-phase Y configuration.
 3768. The method ofclaim 3734, wherein a second conductor is disposed within the firstconduit, wherein at least one sliding electrical connector is coupled tothe first conductor and the second conductor, and wherein heat generatedby at least the one sliding electrical connector is less than heatgenerated by the first conductor or the second conductor.
 3769. Themethod of claim 3734, wherein the first conduit comprises a firstsection and a second section, wherein a thickness of the first sectionis greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3770. The method ofclaim 3734, further comprising flowing an oxidizing fluid through anorifice in the first conduit.
 3771. The method of claim 3734, furthercomprising disposing a perforated tube proximate to the first conduitand flowing an oxidizing fluid through the perforated tube.
 3772. Themethod of claim 3734, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some of thehydrocarbons within the formation.
 3773. A system configured to heat ahydrocarbon containing formation, comprising: a first conductor disposedin a first conduit, wherein the first conduit is disposed within a firstopening in the formation; a second conductor disposed in a secondconduit, wherein the second conduit is disposed within a second openingin the formation; a third conductor disposed in a third conduit, whereinthe third conduit is disposed within a third opening in the formation,wherein the first, second, and third conductors are electrically coupledin a 3-phase Y configuration, and wherein the first, second, and thirdconductors are configured to provide heat to at least a portion of theformation during use; and wherein the system is configured to allow heatto transfer from the first, second, and third conductors to a selectedsection of the formation during use.
 3774. The system of claim 3773,wherein the first, second, and third conductors are further configuredto generate heat during application of an electrical current to thefirst conductor.
 3775. The system of claim 3773, wherein the first,second, and third conductors comprise a pipe.
 3776. The system of claim3773, wherein the first, second, and third conductors comprise stainlesssteel.
 3777. The system of claim 3773, wherein the first, second, andthird openings comprise a diameter of at least approximately 5 cm. 3778.The system of claim 3773, further comprising a first sliding electricalconnector coupled to the first conductor and a second sliding electricalconnector coupled to the second conductor and a third sliding electricalconnector coupled to the third conductor.
 3779. The system of claim3773, further comprising a first sliding electrical connector coupled tothe first conductor, wherein the first sliding electrical connector isfurther coupled to the first conduit.
 3780. The system of claim 3773,further comprising a second sliding electrical connector coupled to thesecond conductor, wherein the second sliding electrical connector isfurther coupled to the second conduit.
 3781. The system of claim 3773,further comprising a third sliding electrical connector coupled to thethird conductor, wherein the third sliding electrical connector isfurther coupled to the third conduit.
 3782. The system of claim 3773,wherein each of the first, second, and third conduits comprises a firstsection and a second section, wherein a thickness of the first sectionis greater than a thickness of the second section such that heatradiated from each of the first, second, and third conductors to thesection along the first section of each of the conduits is less thanheat radiated from the first, second, and third conductors to thesection along the second section of each of the conduits.
 3783. Thesystem of claim 3773, further comprising a fluid disposed within thefirst, second, and third conduits, wherein the fluid is configured tomaintain a pressure within the first conduit to substantially inhibitdeformation of the first, second, and third conduits during use. 3784.The system of claim 3773, further comprising a thermally conductivefluid disposed within the first, second, and third conduits.
 3785. Thesystem of claim 3773, further comprising a thermally conductive fluiddisposed within the first, second, and third conduits, wherein thethermally conductive fluid comprises helium.
 3786. The system of claim3773, further comprising a fluid disposed within the first, second, andthird conduits, wherein the fluid is configured to substantially inhibitarcing between the first, second, and third conductors and the first,second, and third conduits during use.
 3787. The system of claim 3773,further comprising at least one tube disposed within the first, second,and third openings external to the first, second, and third conduits,wherein at least the one tube is configured to remove vapor producedfrom at least the heated portion of the formation such that a pressurebalance is maintained between the first, second, and third conduits andthe first, second, and third openings to substantially inhibitdeformation of the first, second, and third conduits during use. 3788.The system of claim 3773, wherein the first, second, and thirdconductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3789. Thesystem of claim 3773, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation.3790. The system of claim 3773, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation, and wherein at least the one overburden casingcomprises steel.
 3791. The system of claim 3773, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing is further disposed in cement.
 3792. The system of claim 3773,further comprising at least one overburden casing coupled to the first,second, and third openings, wherein at least the one overburden casingis disposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings.
 3793. The system of claim3773, further comprising at least one overburden casing coupled to thefirst, second, and third openings, wherein at least the one overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings, and wherein the packingmaterial is further configured to substantially inhibit a flow of fluidbetween the first, second, and third openings and at least the oneoverburden casing during use.
 3794. The system of claim 3773, whereinthe heated section of the formation is substantially pyrolyzed.
 3795. Asystem configurable to heat a hydrocarbon containing formation,comprising: a first conductor configurable to be disposed in a firstconduit, wherein the first conduit is configurable to be disposed withina first opening in the formation; a second conductor configurable to bedisposed in a second conduit, wherein the second conduit is configurableto be disposed within a second opening in the formation; a thirdconductor configurable to be disposed in a third conduit, wherein thethird conduit is configurable to be disposed within a third opening inthe formation, wherein the first, second, and third conductors arefurther configurable to be electrically coupled in a 3-phase Yconfiguration, and wherein the first, second, and third conductors arefurther configurable to provide heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer from the first, second, and third conductors to aselected section of the formation during use.
 3796. The system of claim3795, wherein the first, second, and third conductors are furtherconfigurable to generate heat during application of an electricalcurrent to the first conductor.
 3797. The system of claim 3795, whereinthe first, second, and third conductors comprise a pipe.
 3798. Thesystem of claim 3795, wherein the first, second, and third conductorscomprise stainless steel.
 3799. The system of claim 3795, wherein thefirst, second, and third openings comprise a diameter of at leastapproximately 5 cm.
 3800. The system of claim 3795, further comprising afirst sliding electrical connector coupled to the first conductor and asecond sliding electrical connector coupled to the second conductor anda third sliding electrical connector coupled to the third conductor.3801. The system of claim 3795, further comprising a first slidingelectrical connector coupled to the first conductor, wherein the firstsliding electrical connector is further coupled to the first conduit.3802. The system of claim 3795, further comprising a second slidingelectrical connector coupled to the second conductor, wherein the secondsliding electrical connector is further coupled to the second conduit.3803. The system of claim 3795, further comprising a third slidingelectrical connector coupled to the third conductor, wherein the thirdsliding electrical connector is further coupled to the third conduit.3804. The system of claim 3795, wherein each of the first, second, andthird conduits comprises a first section and a second section, wherein athickness of the first section is greater than a thickness of the secondsection such that heat radiated from each of the first, second, andthird conductors to the section along the first section of each of theconduits is less than heat radiated from the first, second, and thirdconductors to the section along the second section of each of theconduits.
 3805. The system of claim 3795, further comprising a fluiddisposed within the first, second, and third conduits, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first, second, and thirdconduits during use.
 3806. The system of claim 3795, further comprisinga thermally conductive fluid disposed within the first, second, andthird conduits.
 3807. The system of claim 3795, further comprising athermally conductive fluid disposed within the first, second, and thirdconduits, wherein the thermally conductive fluid comprises helium. 3808.The system of claim 3795, further comprising a fluid disposed within thefirst, second, and third conduits, wherein the fluid is configurable tosubstantially inhibit arcing between the first, second, and thirdconductors and the first, second, and third conduits during use. 3809.The system of claim 3795, further comprising at least one tube disposedwithin the first, second, and third openings external to the first,second, and third conduits, wherein at least the one tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between thefirst, second, and third conduits and the first, second, and thirdopenings to substantially inhibit deformation of the first, second, andthird conduits during use.
 3810. The system of claim 3795, wherein thefirst, second, and third conductors are further configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3811. The system of claim 3795, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation.
 3812. The system of claim 3795, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing comprises steel.
 3813. The system of claim 3795, furthercomprising at least one overburden casing coupled to the first, second,and third openings, wherein at least the one overburden casing isdisposed in an overburden of the formation, and wherein at least the oneoverburden casing is further disposed in cement.
 3814. The system ofclaim 3795, further comprising at least one overburden casing coupled tothe first, second, and third openings, wherein at least the oneoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings.
 3815. Thesystem of claim 3795, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings, and whereinthe packing material is further configurable to substantially inhibit aflow of fluid between the first, second, and third openings and at leastthe one overburden casing during use.
 3816. The system of claim 3795,wherein the heated section of the formation is substantially pyrolyzed.3817. The system of claim 3795, wherein the system is configured to heata hydrocarbon containing formation, and wherein the system comprises: afirst conductor disposed in a first conduit, wherein the first conduitis disposed within a first opening in the formation; a second conductordisposed in a second conduit, wherein the second conduit is disposedwithin a second opening in the formation; a third conductor disposed ina third conduit, wherein the third conduit is disposed within a thirdopening in the formation, wherein the first, second, and thirdconductors are electrically coupled in a 3-phase Y configuration, andwherein the first, second, and third conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst, second, and third conductors to a selected section of theformation during use.
 3818. An in situ method for heating a hydrocarboncontaining formation, comprising: applying an electrical current to afirst conductor to provide heat to at least a portion of the formation,wherein the first conductor is disposed in a first conduit, and whereinthe first conduit is disposed within a first opening in the formation;applying an electrical current to a second conductor to provide heat toat least a portion of the formation, wherein the second conductor isdisposed in a second conduit, and wherein the second conduit is disposedwithin a second opening in the formation; applying an electrical currentto a third conductor to provide heat to at least a portion of theformation, wherein the third conductor is disposed in a third conduit,and wherein the third conduit is disposed within a third opening in theformation; and allowing the heat to transfer from the first, second, andthird conductors to a selected section of the formation.
 3819. Themethod of claim 3818, wherein the first, second, and third conductorscomprise a pipe.
 3820. The method of claim 3818, wherein the first,second, and third conductors comprise stainless steel.
 3821. The methodof claim 3818, wherein the first, second, and third conduits comprisestainless steel.
 3822. The method of claim 3818, wherein the providedheat comprises approximately 650 W/m to approximately 1650 W/m. 3823.The method of claim 3818, further comprising determining a temperaturedistribution in the first, second, and third conduits using anelectromagnetic signal provided to the first, second, and thirdconduits.
 3824. The method of claim 3818, further comprising monitoringthe applied electrical current.
 3825. The method of claim 3818, furthercomprising monitoring a voltage applied to the first, second, and thirdconductors.
 3826. The method of claim 3818, further comprisingmonitoring a temperature in the first, second, and third conduits withat least one thermocouple.
 3827. The method of claim 3818, furthercomprising maintaining a sufficient pressure between the first, second,and third conduits and the first, second, and third openings tosubstantially inhibit deformation of the first, second, and thirdconduits.
 3828. The method of claim 3818, further comprising providing athermally conductive fluid within the first, second, and third conduits.3829. The method of claim 3818, further comprising providing a thermallyconductive fluid within the first, second, and third conduits, whereinthe thermally conductive fluid comprises helium.
 3830. The method ofclaim 3818, further comprising inhibiting arcing between the first,second, and third conductors and the first, second, and third conduitswith a fluid disposed within the first, second, and third conduits.3831. The method of claim 3818, further comprising removing a vapor fromthe first, second, and third openings using at least one perforated tubedisposed proximate to the first, second, and third conduits in thefirst, second, and third openings to control a pressure in the first,second, and third openings.
 3832. The method of claim 3818, wherein thefirst, second, and third conduits comprise a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the first,second, and third conductors to the section along the first section ofthe first, second, and third conduits is less than heat radiated fromthe first, second, and third conductors to the section along the secondsection of the first, second, and third conduits.
 3833. The method ofclaim 3818, further comprising flowing an oxidizing fluid through anorifice in the first, second, and third conduits.
 3834. The method ofclaim 3818, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the hydrocarbonswithin the formation.
 3835. A system configured to heat a hydrocarboncontaining formation, comprising: a first conductor disposed in aconduit, wherein the conduit is disposed within an opening in theformation; and a second conductor disposed in the conduit, wherein thesecond conductor is electrically coupled to the first conductor with aconnector, and wherein the first and second conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst and second conductors to a selected section of the formationduring use.
 3836. The system of claim 3835, wherein the first conductoris further configured to generate heat during application of anelectrical current to the first conductor.
 3837. The system of claim3835, wherein the first and second conductors comprise a pipe.
 3838. Thesystem of claim 3835, wherein the first and second conductors comprisestainless steel.
 3839. The system of claim 3835, wherein the conduitcomprises stainless steel.
 3840. The system of claim 3835, furthercomprising a centralizer configured to maintain a location of the firstand second conductors within the conduit.
 3841. The system of claim3835, further comprising a centralizer configured to maintain a locationof the first and second conductors within the conduit, wherein thecentralizer comprises ceramic material.
 3842. The system of claim 3835,further comprising a centralizer configured to maintain a location ofthe first and second conductors within the conduit, wherein thecentralizer comprises ceramic material and stainless steel.
 3843. Thesystem of claim 3835, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3844. The system of claim 3835, furthercomprising a lead-in conductor coupled to the first and secondconductors, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 3845. The systemof claim 3835, further comprising a lead-in conductor coupled to thefirst and second conductors, wherein the lead-in conductor comprisescopper.
 3846. The system of claim 3835, wherein the conduit comprises afirst section and a second section, wherein a thickness of the firstsection is greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3847. The system ofclaim 3835, further comprising a fluid disposed within the conduit,wherein the fluid is configured to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3848. The system of claim 3835, further comprising a thermallyconductive fluid disposed within the conduit.
 3849. The system of claim3835, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3850. The system of claim 3835, further comprising a fluid disposedwithin the conduit, wherein the fluid is configured to substantiallyinhibit arcing between the first and second conductors and the conduitduring use.
 3851. The system of claim 3835, further comprising a tubedisposed within the opening external to the conduit, wherein the tube isconfigured to remove vapor produced from at least the heated portion ofthe formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3852. The system of claim 3835, wherein the firstand second conductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3853. Thesystem of claim 3835, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3854. The system of claim 3835, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3855. The system of claim 3835,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3856. Thesystem of claim 3835, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3857. The system ofclaim 3835, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3858. The system ofclaim 3835, wherein the heated section of the formation is substantiallypyrolyzed.
 3859. A system configurable to heat a hydrocarbon containingformation, comprising: a first conductor configurable to be disposed ina conduit, wherein the conduit is configurable to be disposed within anopening in the formation; a second conductor configurable to be disposedin the conduit, wherein the second conductor is configurable to beelectrically coupled to the first conductor with a connector, andwherein the first and second conductors are further configurable toprovide heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from thefirst and second conductors to a selected section of the formationduring use.
 3860. The system of claim 3859, wherein the first conductoris further configurable to generate heat during application of anelectrical current to the first conductor.
 3861. The system of claim3859, wherein the first and second conductors comprise a pipe.
 3862. Thesystem of claim 3859, wherein the first and second conductors comprisestainless steel.
 3863. The system of claim 3859, wherein the conduitcomprises stainless steel.
 3864. The system of claim 3859, furthercomprising a centralizer configurable to maintain a location of thefirst and second conductors within the conduit.
 3865. The system ofclaim 3859, further comprising a centralizer configurable to maintain alocation of the first and second conductors within the conduit, whereinthe centralizer comprises ceramic material.
 3866. The system of claim3859, further comprising a centralizer configurable to maintain alocation of the first and second conductors within the conduit, whereinthe centralizer comprises ceramic material and stainless steel. 3867.The system of claim 3859, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3868. The system of claim 3859, furthercomprising a lead-in conductor coupled to the first and secondconductors, wherein the lead-in conductor comprises a low resistanceconductor configurable to generate substantially no heat.
 3869. Thesystem of claim 3859, further comprising a lead-in conductor coupled tothe first and second conductors, wherein the lead-in conductor comprisescopper.
 3870. The system of claim 3859, wherein the conduit comprises afirst section and a second section, wherein a thickness of the firstsection is greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3871. The system ofclaim 3859, further comprising a fluid disposed within the conduit,wherein the fluid is configurable to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3872. The system of claim 3859, further comprising a thermallyconductive fluid disposed within the conduit.
 3873. The system of claim3859, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3874. The system of claim 3859, further comprising a fluid disposedwithin the conduit, wherein the fluid is configurable to substantiallyinhibit arcing between the first and second conductors and the conduitduring use.
 3875. The system of claim 3859, further comprising a tubedisposed within the opening external to the conduit, wherein the tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3876. The system of claim 3859, wherein the firstand second conductors are further configurable to generate radiant heatof approximately 650 W/m to approximately 1650 W/m during use.
 3877. Thesystem of claim 3859, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3878. The system of claim 3859, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3879. The system of claim 3859,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3880. Thesystem of claim 3859, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3881. The system ofclaim 3859, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3882. The system ofclaim 3859, wherein the heated section of the formation is substantiallypyrolyzed.
 3883. The system of claim 3859, wherein the system isconfigured to heat a hydrocarbon containing formation, and wherein thesystem comprises: a first conductor disposed in a conduit, wherein theconduit is disposed within an opening in the formation; a secondconductor disposed in the conduit, wherein the second conductor iselectrically coupled to the first conductor with a connector, andwherein the first and second conductors are configured to provide heatto at least a portion of the formation during use; and wherein thesystem is configured to allow heat to transfer from the first and secondconductors to a selected section of the formation during use.
 3884. Anin situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to at least two conductors toprovide heat to at least a portion of the formation, wherein at leastthe two conductors are disposed within a conduit, wherein the conduit isdisposed within an opening in the formation, and wherein at least thetwo conductors are electrically coupled with a connector; and allowingheat to transfer from at least the two conductors to a selected sectionof the formation.
 3885. The method of claim 3884, wherein at least thetwo conductors comprise a pipe.
 3886. The method of claim 3884, whereinat least the two conductors comprise stainless steel.
 3887. The methodof claim 3884, wherein the conduit comprises stainless steel.
 3888. Themethod of claim 3884, further comprising maintaining a location of atleast the two conductors in the conduit with a centralizer.
 3889. Themethod of claim 3884, further comprising maintaining a location of atleast the two conductors in the conduit with a centralizer, wherein thecentralizer comprises ceramic material.
 3890. The method of claim 3884,further comprising maintaining a location of at least the two conductorsin the conduit with a centralizer, wherein the centralizer comprisesceramic material and stainless steel.
 3891. The method of claim 3884,wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 3892. The method of claim 3884, furthercomprising determining a temperature distribution in the conduit usingan electromagnetic signal provided to the conduit.
 3893. The method ofclaim 3884, further comprising monitoring the applied electricalcurrent.
 3894. The method of claim 3884, further comprising monitoring avoltage applied to at least the two conductors.
 3895. The method ofclaim 3884, further comprising monitoring a temperature in the conduitwith at least one thermocouple.
 3896. The method of claim 3884, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3897.The method of claim 3884, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3898. The method of claim 3884, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3899. The method of claim 3884,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3900. The method of claim 3884, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3901. Themethod of claim 3884, further comprising maintaining a sufficientpressure between the conduit and the formation to substantially inhibitdeformation of the conduit.
 3902. The method of claim 3884, furthercomprising providing a thermally conductive fluid within the conduit.3903. The method of claim 3884, further comprising providing a thermallyconductive fluid within the conduit, wherein the thermally conductivefluid comprises helium.
 3904. The method of claim 3884, furthercomprising inhibiting arcing between at least the two conductors and theconduit with a fluid disposed within the conduit.
 3905. The method ofclaim 3884, further comprising removing a vapor from the opening using aperforated tube disposed proximate to the conduit in the opening tocontrol a pressure in the opening.
 3906. The method of claim 3884,further comprising flowing a corrosion inhibiting fluid through aperforated tube disposed proximate to the conduit in the opening. 3907.The method of claim 3884, wherein the conduit comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom the first conductor to the section along the first section of theconduit is less than heat radiated from the first conductor to thesection along the second section of the conduit.
 3908. The method ofclaim 3884, further comprising flowing an oxidizing fluid through anorifice in the conduit.
 3909. The method of claim 3884, furthercomprising disposing a perforated tube proximate to the conduit andflowing an oxidizing fluid through the perforated tube.
 3910. The methodof claim 3884, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the hydrocarbonswithin the formation.
 3911. A system configured to heat a hydrocarboncontaining formation, comprising: at least one conductor disposed in aconduit, wherein the conduit is disposed within an opening in theformation, and wherein at least the one conductor is configured toprovide heat to at least a first portion of the formation during use; atleast one sliding connector, wherein at least the one sliding connectoris coupled to at least the one conductor, wherein at least the onesliding connector is configured to provide heat during use, and whereinheat provided by at least the one sliding connector is substantiallyless than the heat provided by at least the one conductor during use;and wherein the system is configured to allow heat to transfer from atleast the one conductor to a section of the formation during use. 3912.The system of claim 3911, wherein at least the one conductor is furtherconfigured to generate heat during application of an electrical currentto at least the one conductor.
 3913. The system of claim 3911, whereinat least the one conductor comprises a pipe.
 3914. The system of claim3911, wherein at least the one conductor comprises stainless steel.3915. The system of claim 3911, wherein the conduit comprises stainlesssteel.
 3916. The system of claim 3911, further comprising a centralizerconfigured to maintain a location of at least the one conductor withinthe conduit.
 3917. The system of claim 3911, further comprising acentralizer configured to maintain a location of at least the oneconductor within the conduit, wherein the centralizer comprises ceramicmaterial.
 3918. The system of claim 3911, further comprising acentralizer configured to maintain a location of at least the oneconductor within the conduit, wherein the centralizer comprises ceramicmaterial and stainless steel.
 3919. The system of claim 3911, whereinthe opening comprises a diameter of at least approximately 5 cm. 3920.The system of claim 3911, further comprising a lead-in conductor coupledto at least the one conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3921. The system of claim 3911, further comprising a lead-in conductorcoupled to at least the one conductor, wherein the lead-in conductorcomprises copper.
 3922. The system of claim 3911, wherein the conduitcomprises a first section and a second section, wherein a thickness ofthe first section is greater than a thickness of the second section suchthat heat radiated from the first conductor to the section along thefirst section of the conduit is less than heat radiated from the firstconductor to the section along the second section of the conduit. 3923.The system of claim 3911, further comprising a fluid disposed within theconduit, wherein the fluid is configured to maintain a pressure withinthe conduit to substantially inhibit deformation of the conduit duringuse.
 3924. The system of claim 3911, further comprising a thermallyconductive fluid disposed within the conduit.
 3925. The system of claim3911, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3926. The system of claim 3911, further comprising a fluid disposedwithin the conduit, wherein the fluid is configured to substantiallyinhibit arcing between at least the one conductor and the conduit duringuse.
 3927. The system of claim 3911, further comprising a tube disposedwithin the opening external to the conduit, wherein the tube isconfigured to remove vapor produced from at least the heated portion ofthe formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3928. The system of claim 3911, wherein at least theone conductor is further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3929. Thesystem of claim 3911, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3930. The system of claim 3911, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3931. The system of claim 3911,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3932. Thesystem of claim 3911, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3933. The system ofclaim 3911, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3934. The system ofclaim 3911, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3935. The system ofclaim 3911, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3936. Thesystem of claim 3911, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3937. The system of claim 3911, wherein the heated section of theformation is substantially pyrolyzed.
 3938. A system configurable toheat a hydrocarbon containing formation, comprising: at least oneconductor configurable to be disposed in a conduit, wherein the conduitis configurable to be disposed within an opening in the formation, andwherein at least the one conductor is further configurable to provideheat to at least a first portion of the formation during use; at leastone sliding connector, wherein at least the one sliding connector isconfigurable to be coupled to at least the one conductor, wherein atleast the one sliding connector is further configurable to provide heatduring use, and wherein heat provided by at least the one slidingconnector is substantially less than the heat provided by at least theone conductor during use; and wherein the system is configurable toallow heat to transfer from at least the one conductor to a section ofthe formation during use.
 3939. The system of claim 3938, wherein atleast the one conductor is further configurable to generate heat duringapplication of an electrical current to at least the one conductor.3940. The system of claim 3938, wherein at least the one conductorcomprises a pipe.
 3941. The system of claim 3938, wherein at least theone conductor comprises stainless steel.
 3942. The system of claim 3938,wherein the conduit comprises stainless steel.
 3943. The system of claim3938, further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit.
 3944. Thesystem of claim 3938, further comprising a centralizer configurable tomaintain a location of at least the one conductor within the conduit,wherein the centralizer comprises ceramic material.
 3945. The system ofclaim 3938, further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit, wherein thecentralizer comprises ceramic material and stainless steel.
 3946. Thesystem of claim 3938, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3947. The system of claim 3938, furthercomprising a lead-in conductor coupled to at least the one conductor,wherein the lead-in conductor comprises a low resistance conductorconfigurable to generate substantially no heat.
 3948. The system ofclaim 3938, further comprising a lead-in conductor coupled to at leastthe one conductor, wherein the lead-in conductor comprises copper. 3949.The system of claim 3938, wherein the conduit comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom the first conductor to the section along the first section of theconduit is less than heat radiated from the first conductor to thesection along the second section of the conduit.
 3950. The system ofclaim 3938, further comprising a fluid disposed within the conduit,wherein the fluid is configurable to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3951. The system of claim 3938, further comprising a thermallyconductive fluid disposed within the conduit.
 3952. The system of claim3938, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3953. The system of claim 3938, further comprising a fluid disposedwithin the conduit, wherein the fluid is configurable to substantiallyinhibit arcing between at least the one conductor and the conduit duringuse.
 3954. The system of claim 3938, further comprising a tube disposedwithin the opening external to the conduit, wherein the tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3955. The system of claim 3938, wherein at least theone conductor is further configurable to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3956. Thesystem of claim 3938, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3957. The system of claim 3938, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3958. The system of claim 3938,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3959. Thesystem of claim 3938, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3960. The system ofclaim 3938, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3961. The system ofclaim 3938, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3962. The system ofclaim 3938, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3963. Thesystem of claim 3938, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3964. The system of claim 3938, wherein the heated section of theformation is substantially pyrolyzed.
 3965. The system of claim 3938,wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: at least one conductordisposed in a conduit, wherein the conduit is disposed within an openingin the formation, and wherein at least the one conductor is configuredto provide heat to at least a first portion of the formation during use;at least one sliding connector, wherein at least the one slidingconnector is coupled to at least the one conductor, wherein at least theone sliding connector is configured to provide heat during use, andwherein heat provided by at least the one sliding connector issubstantially less than the heat provided by at least the one conductorduring use; and wherein the system is configured to allow heat totransfer from at least the one conductor to a section of the formationduring use.
 3966. An in situ method for heating a hydrocarbon containingformation, comprising: applying an electrical current to at least oneconductor and at least one sliding connector to provide heat to at leasta portion of the formation, wherein at least the one conductor and atleast the one sliding connector are disposed within a conduit, andwherein heat provided by at least the one conductor is substantiallygreater than heat provided by at least the one sliding connector; andallowing the heat to transfer from at least the one conductor and atleast the one sliding connector to a section of the formation.
 3967. Themethod of claim 3966, wherein at least the one conductor comprises apipe.
 3968. The method of claim 3966, wherein at least the one conductorcomprises stainless steel.
 3969. The method of claim 3966, wherein theconduit comprises stainless steel.
 3970. The method of claim 3966,further comprising maintaining a location of at least the one conductorin the conduit with a centralizer.
 3971. The method of claim 3966,further comprising maintaining a location of at least the one conductorin the conduit with a centralizer, wherein the centralizer comprisesceramic material.
 3972. The method of claim 3966, further comprisingmaintaining a location of at least the one conductor in the conduit witha centralizer, wherein the centralizer comprises ceramic material andstainless steel.
 3973. The method of claim 3966, wherein the providedheat comprises approximately 650 W/m to approximately 1650 W/m. 3974.The method of claim 3966, further comprising determining a temperaturedistribution in the conduit using an electromagnetic signal provided tothe conduit.
 3975. The method of claim 3966, further comprisingmonitoring the applied electrical current.
 3976. The method of claim3966, further comprising monitoring a voltage applied to at least theone conductor.
 3977. The method of claim 3966, further comprisingmonitoring a temperature in the conduit with at least one thermocouple.3978. The method of claim 3966, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3979. The method of claim3966, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing comprises steel.
 3980. Themethod of claim 3966, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3981. The method of claim 3966, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3982. The method of claim 3966, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3983. Themethod of claim 3966, further comprising coupling an overburden casingto the opening, wherein a substantially low resistance conductor isdisposed within the overburden casing, and wherein the substantially lowresistance conductor is electrically coupled to at least the oneconductor.
 3984. The method of claim 3966, further comprising couplingan overburden casing to the opening, wherein a substantially lowresistance conductor is disposed within the overburden casing, whereinthe substantially low resistance conductor is electrically coupled to atleast the one conductor, and wherein the substantially low resistanceconductor comprises carbon steel.
 3985. The method of claim 3966,further comprising coupling an overburden casing to the opening, whereina substantially low resistance conductor is disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein themethod further comprises maintaining a location of the substantially lowresistance conductor in the overburden casing with a centralizersupport.
 3986. The method of claim 3966, further comprising electricallycoupling a lead-in conductor to at least the one conductor, wherein thelead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3987. The method of claim 3966, furthercomprising electrically coupling a lead-in conductor to at least the oneconductor, wherein the lead-in conductor comprises copper.
 3988. Themethod of claim 3966, further comprising maintaining a sufficientpressure between the conduit and the formation to substantially inhibitdeformation of the conduit.
 3989. The method of claim 3966, furthercomprising providing a thermally conductive fluid within the conduit.3990. The method of claim 3966, further comprising providing a thermallyconductive fluid within the conduit, wherein the thermally conductivefluid comprises helium.
 3991. The method of claim 3966, furthercomprising inhibiting arcing between the conductor and the conduit witha fluid disposed within the conduit.
 3992. The method of claim 3966,further comprising removing a vapor from the opening using a perforatedtube disposed proximate to the conduit in the opening to control apressure in the opening.
 3993. The method of claim 3966, furthercomprising flowing a corrosion inhibiting fluid through a perforatedtube disposed proximate to the conduit in the opening.
 3994. The methodof claim 3966, further comprising flowing an oxidizing fluid through anorifice in the conduit.
 3995. The method of claim 3966, furthercomprising disposing a perforated tube proximate to the conduit andflowing an oxidizing fluid through the perforated tube.
 3996. The methodof claim 3966, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the hydrocarbonswithin the formation.
 3997. A system configured to heat a hydrocarboncontaining formation, comprising: at least one elongated member disposedwithin an opening in the formation, wherein at least the one elongatedmember is configured to provide heat to at least a portion of theformation during use; and wherein the system is configured to allow heatto transfer from at least the one elongated member to a section of theformation during use.
 3998. The system of claim 3997, wherein at leastthe one elongated member comprises stainless steel.
 3999. The system ofclaim 3997, wherein at least the one elongated member is furtherconfigured to generate heat during application of an electrical currentto at least the one elongated member.
 4000. The system of claim 3997,further comprising a support member coupled to at least the oneelongated member, wherein the support member is configured to support atleast the one elongated member.
 4001. The system of claim 3997, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configured to support at least theone elongated member, and wherein the support member comprises openings.4002. The system of claim 3997, further comprising a support membercoupled to at least the one elongated member, wherein the support memberis configured to support at least the one elongated member, wherein thesupport member comprises openings, wherein the openings are configuredto flow a fluid along a length of at least the one elongated memberduring use, and wherein the fluid is configured to substantially inhibitcarbon deposition on or proximate to at least the one elongated memberduring use.
 4003. The system of claim 3997, further comprising a tubedisposed in the opening, wherein the tube comprises openings, whereinthe openings are configured to flow a fluid along a length of at leastthe one elongated member during use, and wherein the fluid is configuredto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use.
 4004. The system of claim 3997,further comprising a centralizer coupled to at least the one elongatedmember, wherein the centralizer is configured to electrically isolate atleast the one elongated member.
 4005. The system of claim 3997, furthercomprising a centralizer coupled to at least the one elongated memberand a support member coupled to at least the one elongated member,wherein the centralizer is configured to maintain a location of at leastthe one elongated member on the support member.
 4006. The system ofclaim 3997, wherein the opening comprises a diameter of at leastapproximately 5 cm.
 4007. The system of claim 3997, further comprising alead-in conductor coupled to at least the one elongated member, whereinthe lead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 4008. The system of claim 3997, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises a rubber insulatedconductor.
 4009. The system of claim 3997, further comprising a lead-inconductor coupled to at least the one elongated member, wherein thelead-in conductor comprises copper wire.
 4010. The system of claim 3997,further comprising a lead-in conductor coupled to at least the oneelongated member with a cold pin transition conductor.
 4011. The systemof claim 3997, further comprising a lead-in conductor coupled to atleast the one elongated member with a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 4012. The system of claim 3997, whereinat least the one elongated member is arranged in a series electricalconfiguration.
 4013. The system of claim 3997, wherein at least the oneelongated member is arranged in a parallel electrical configuration.4014. The system of claim 3997, wherein at least the one elongatedmember is configured to generate radiant heat of approximately 650 W/mto approximately 1650 W/m during use.
 4015. The system of claim 3997,further comprising a perforated tube disposed in the opening external toat least the one elongated member, wherein the perforated tube isconfigured to remove vapor from the opening to control a pressure in theopening during use.
 4016. The system of claim 3997, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 4017. The systemof claim 3997, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 4018.The system of claim 3997, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4019. The system of claim 3997, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4020. The system of claim 3997, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.4021. The system of claim 3997, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configured to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 4022.The system of claim 3997, wherein the heated section of the formation issubstantially pyrolyzed.
 4023. A system configurable to heat ahydrocarbon containing formation, comprising: at least one elongatedmember configurable to be disposed within an opening in the formation,wherein at least the one elongated member is further configurable toprovide heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from atleast the one elongated member to a section of the formation during use.4024. The system of claim 4023, wherein at least the one elongatedmember comprises stainless steel.
 4025. The system of claim 4023,wherein at least the one elongated member is further configurable togenerate heat during application of an electrical current to at leastthe one elongated member.
 4026. The system of claim 4023, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configurable to support at leastthe one elongated member.
 4027. The system of claim 4023, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configurable to support at leastthe one elongated member, and wherein the support member comprisesopenings.
 4028. The system of claim 4023, further comprising a supportmember coupled to at least the one elongated member, wherein the supportmember is configurable to support at least the one elongated member,wherein the support member comprises openings, wherein the openings areconfigurable to flow a fluid along a length of at least the oneelongated member during use, and wherein the fluid is configurable tosubstantially inhibit carbon deposition on or proximate to at least theone elongated member during use.
 4029. The system of claim 4023, furthercomprising a tube disposed in the opening, wherein the tube comprisesopenings, wherein the openings are configurable to flow a fluid along alength of at least the one elongated member during use, and wherein thefluid is configurable to substantially inhibit carbon deposition on orproximate to at least the one elongated member during use.
 4030. Thesystem of claim 4023, further comprising a centralizer coupled to atleast the one elongated member, wherein the centralizer is configurableto electrically isolate at least the one elongated member.
 4031. Thesystem of claim 4023, further comprising a centralizer coupled to atleast the one elongated member and a support member coupled to at leastthe one elongated member, wherein the centralizer is configurable tomaintain a location of at least the one elongated member on the supportmember.
 4032. The system of claim 4023, wherein the opening comprises adiameter of at least approximately 5 cm.
 4033. The system of claim 4023,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.4034. The system of claim 4023, further comprising a lead-in conductorcoupled to at least the one elongated member, wherein the lead-inconductor comprises a rubber insulated conductor.
 4035. The system ofclaim 4023, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises copperwire.
 4036. The system of claim 4023, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor.
 4037. The system of claim 4023, further comprisinga lead-in conductor coupled to at least the one elongated member with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4038. Thesystem of claim 4023, wherein at least the one elongated member isarranged in a series electrical configuration.
 4039. The system of claim4023, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 4040. The system of claim 4023,wherein at least the one elongated member is configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 4041. The system of claim 4023, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configurable to remove vapor fromthe opening to control a pressure in the opening during use.
 4042. Thesystem of claim 4023, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 4043. The system of claim 4023, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4044. The system of claim 4023,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 4045. Thesystem of claim 4023, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 4046. The system ofclaim 4023, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 4047. The system of claim 4023, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 4048. The system of claim 4023, whereinthe heated section of the formation is substantially pyrolyzed. 4049.The system of claim 4023, wherein the system is configured to heat ahydrocarbon containing formation, and wherein the system comprises: atleast one elongated member disposed within an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; and wherein thesystem is configured to allow heat to transfer from at least the oneelongated member to a section of the formation during use.
 4050. An insitu method for heating a hydrocarbon containing formation, comprising:applying an electrical current to at least one elongated member toprovide heat to at least a portion of the formation, wherein at leastthe one elongated member is disposed within an opening of the formation;and allowing heat to transfer from at least the one elongated member toa section of the formation.
 4051. The method of claim 4050, wherein atleast the one elongated member comprises a metal strip.
 4052. The methodof claim 4050, wherein at least the one elongated member comprises ametal rod.
 4053. The method of claim 4050, wherein at least the oneelongated member comprises stainless steel.
 4054. The method of claim4050, further comprising supporting at least the one elongated member ona center support member.
 4055. The method of claim 4050, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises a tube.4056. The method of claim 4050, further comprising electricallyisolating at least the one elongated member with a centralizer. 4057.The method of claim 4050, further comprising laterally spacing at leastthe one elongated member with a centralizer.
 4058. The method of claim4050, further comprising electrically coupling at least the oneelongated member in a series configuration.
 4059. The method of claim4050, further comprising electrically coupling at least the oneelongated member in a parallel configuration.
 4060. The method of claim4050, wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 4061. The method of claim 4050, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 4062. The method of claim 4050, furthercomprising monitoring the applied electrical current.
 4063. The methodof claim 4050, further comprising monitoring a voltage applied to atleast the one elongated member.
 4064. The method of claim 4050, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 4065. The method of claim 4050, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,the method further comprising flowing an oxidizing fluid through theopenings to substantially inhibit carbon deposition proximate to or onat least the one elongated member.
 4066. The method of claim 4050,further comprising flowing an oxidizing fluid through a tube disposedproximate to at least the one elongated member to substantially inhibitcarbon deposition proximate to or on at least the one elongated member.4067. The method of claim 4050, further comprising flowing an oxidizingfluid through an opening in at least the one elongated member tosubstantially inhibit carbon deposition proximate to or on at least theone elongated member.
 4068. The method of claim 4050, further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 4069. The methodof claim 4050, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor.
 4070. The method of claim 4050, further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember using a cold pin transition conductor, wherein the cold pintransition conductor comprises a substantially low resistance insulatedconductor.
 4071. The method of claim 4050, further comprising couplingan overburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 4072. The method of claim4050, further comprising coupling an overburden casing to the opening,wherein the overburden casing comprises steel.
 4073. The method of claim4050, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in cement.
 4074. The method ofclaim 4050, further comprising coupling an overburden casing to theopening, wherein a packing material is disposed at a junction of theoverburden casing and the opening.
 4075. The method of claim 4050,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the method further comprises inhibiting aflow of fluid between the opening and the overburden casing with thepacking material.
 4076. The method of claim 4050, further comprisingheating at least the portion of the formation to substantially pyrolyzeat least some of the hydrocarbons within the formation.
 4077. A systemconfigured to heat a hydrocarbon containing formation, comprising: atleast one elongated member disposed within an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a conduit disposed within the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto the opening during use, and wherein the oxidizing fluid is selectedto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use; and wherein the system isconfigured to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 4078. The system ofclaim 4077, wherein at least the one elongated member comprisesstainless steel.
 4079. The system of claim 4077, wherein at least theone elongated member is further configured to generate heat duringapplication of an electrical current to at least the one elongatedmember.
 4080. The system of claim 4077, wherein at least the oneelongated member is coupled to the conduit, wherein the conduit isfurther configured to support at least the one elongated member. 4081.The system of claim 4077, wherein at least the one elongated member iscoupled to the conduit, wherein the conduit is further configured tosupport at least the one elongated member, and wherein the conduitcomprises openings.
 4082. The system of claim 4077, further comprising acentralizer coupled to at least the one elongated member and theconduit, wherein the centralizer is configured to electrically isolateat least the one elongated member from the conduit.
 4083. The system ofclaim 4077, further comprising a centralizer coupled to at least the oneelongated member and the conduit, wherein the centralizer is configuredto maintain a location of at least the one elongated member on theconduit.
 4084. The system of claim 4077, wherein the opening comprises adiameter of at least approximately 5 cm.
 4085. The system of claim 4077,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises a lowresistance conductor configured to generate substantially no heat. 4086.The system of claim 4077, further comprising a lead-in conductor coupledto at least the one elongated member, wherein the lead-in conductorcomprises a rubber insulated conductor.
 4087. The system of claim 4077,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises copper wire.4088. The system of claim 4077, further comprising a lead-in conductorcoupled to at least the one elongated member with a cold pin transitionconductor.
 4089. The system of claim 4077, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4090. Thesystem of claim 4077, wherein at least the one elongated member isarranged in a series electrical configuration.
 4091. The system of claim4077, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 4092. The system of claim 4077,wherein at least the one elongated member is configured to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 4093. The system of claim 4077, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configured to remove vapor fromthe opening to control a pressure in the opening during use.
 4094. Thesystem of claim 4077, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 4095. The system of claim 4077, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4096. The system of claim 4077,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 4097. Thesystem of claim 4077, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 4098. The system ofclaim 4077, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 4099. The system of claim 4077, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configured tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 4100. The system of claim 4077, whereinthe heated section of the formation is substantially pyrolyzed.
 4101. Asystem configurable to heat a hydrocarbon containing formation,comprising: at least one elongated member configurable to be disposedwithin an opening in the formation, wherein at least the one elongatedmember is further configurable to provide heat to at least a portion ofthe formation during use; a conduit configurable to be disposed withinthe opening, wherein the conduit is further configurable to provide anoxidizing fluid from the oxidizing fluid source to the opening duringuse, and wherein the system is configurable to allow the oxidizing fluidto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use; and wherein the system is furtherconfigurable to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 4102. The system ofclaim 4101, wherein at least the one elongated member comprisesstainless steel.
 4103. The system of claim 4101, wherein at least theone elongated member is further configurable to generate heat duringapplication of an electrical current to at least the one elongatedmember.
 4104. The system of claim 4101, wherein at least the oneelongated member is coupled to the conduit, wherein the conduit isfurther configurable to support at least the one elongated member. 4105.The system of claim 4101, wherein at least the one elongated member iscoupled to the conduit, wherein the conduit is further configurable tosupport at least the one elongated member, and wherein the conduitcomprises openings.
 4106. The system of claim 4101, further comprising acentralizer coupled to at least the one elongated member and theconduit, wherein the centralizer is configurable to electrically isolateat least the one elongated member from the conduit.
 4107. The system ofclaim 4101, further comprising a centralizer coupled to at least the oneelongated member and the conduit, wherein the centralizer isconfigurable to maintain a location of at least the one elongated memberon the conduit.
 4108. The system of claim 4101, wherein the openingcomprises a diameter of at least approximately 5 cm.
 4109. The system ofclaim 4101, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.4110. The system of claim 4101, further comprising a lead-in conductorcoupled to at least the one elongated member, wherein the lead-inconductor comprises a rubber insulated conductor.
 4111. The system ofclaim 4101, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises copperwire.
 4112. The system of claim 4101, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor.
 4113. The system of claim 4101, further comprisinga lead-in conductor coupled to at least the one elongated member with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4114. Thesystem of claim 4101, wherein at least the one elongated member isarranged in a series electrical configuration.
 4115. The system of claim4101, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 4116. The system of claim 4101,wherein at least the one elongated member is configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 4117. The system of claim 4101, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configurable to remove vapor fromthe opening to control a pressure in the opening during use.
 4118. Thesystem of claim 4101, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 4119. The system of claim 4101, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4120. The system of claim 4101,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 4121. Thesystem of claim 4101, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 4122. The system ofclaim 4101, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 4123. The system of claim 4101, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 4124. The system of claim 4101, whereinthe heated section of the formation is substantially pyrolyzed. 4125.The system of claim 4101, wherein the system is configured to heat ahydrocarbon containing formation, and wherein the system comprises: atleast one elongated member disposed within an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a conduit disposed within the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto the opening during use, and wherein the oxidizing fluid is selectedto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use; and wherein the system isconfigured to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 4126. An in situ methodfor heating a hydrocarbon containing formation, comprising: applying anelectrical current to at least one elongated member to provide heat toat least a portion of the formation, wherein at least the one elongatedmember is disposed within an opening in the formation; providing anoxidizing fluid to at least the one elongated member to substantiallyinhibit carbon deposition on or proximate to at least the one elongatedmember; and allowing heat to transfer from at least the one elongatedmember to a section of the formation.
 4127. The method of claim 4126,wherein at least the one elongated member comprises a metal strip. 4128.The method of claim 4126, wherein at least the one elongated membercomprises a metal rod.
 4129. The method of claim 4126, wherein at leastthe one elongated member comprises stainless steel.
 4130. The method ofclaim 4126, further comprising supporting at least the one elongatedmember on a center support member.
 4131. The method of claim 4126,further comprising supporting at least the one elongated member on acenter support member, wherein the center support member comprises atube.
 4132. The method of claim 4126, further comprising electricallyisolating at least the one elongated member with a centralizer. 4133.The method of claim 4126, further comprising laterally spacing at leastthe one elongated member with a centralizer.
 4134. The method of claim4126, further comprising electrically coupling at least the oneelongated member in a series configuration.
 4135. The method of claim4126, further comprising electrically coupling at least the oneelongated member in a parallel configuration.
 4136. The method of claim4126, wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 4137. The method of claim 4126, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 4138. The method of claim 4126, furthercomprising monitoring the applied electrical current.
 4139. The methodof claim 4126, further comprising monitoring a voltage applied to atleast the one elongated member.
 4140. The method of claim 4126, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 4141. The method of claim 4126, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,wherein providing the oxidizing fluid to at least the one elongatedmember comprises flowing the oxidizing fluid through the openings in thecenter support member.
 4142. The method of claim 4126, wherein providingthe oxidizing fluid to at least the one elongated member comprisesflowing the oxidizing fluid through orifices in a tube disposed in theopening proximate to at least the one elongated member.
 4143. The methodof claim 4126, further comprising electrically coupling a lead-inconductor to at least the one elongated member, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 4144. The method of claim 4126, furthercomprising electrically coupling a lead-in conductor to at least the oneelongated member using a cold pin transition conductor.
 4145. The methodof claim 4126, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4146. Themethod of claim 4126, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 4147. The method of claim 4126, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing comprises steel.
 4148. The method of claim 4126,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in cement.
 4149. The method of claim4126, further comprising coupling an overburden casing to the opening,wherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4150. The method of claim 4126, furthercomprising coupling an overburden casing to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening, and wherein the method further comprises inhibiting a flowof fluid between the opening and the overburden casing with the packingmaterial.
 4151. The method of claim 4126, further comprising heating atleast the portion of the formation to substantially pyrolyze at leastsome of the hydrocarbons within the formation.
 4152. An in situ methodfor heating a hydrocarbon containing formation, comprising: oxidizing afuel fluid in a heater; providing at least a portion of the oxidizedfuel fluid into a conduit disposed in an opening of the formation;allowing heat to transfer from the oxidized fuel fluid to a section ofthe formation; and allowing additional heat to transfer from an electricheater disposed in the opening to the section of the formation, whereinheat is allowed to transfer substantially uniformly along a length ofthe opening.
 4153. The method of claim 4152, wherein providing at leastthe portion of the oxidized fuel fluid into the opening comprisesflowing the oxidized fuel fluid through a perforated conduit disposed inthe opening.
 4154. The method of claim 4152, wherein providing at leastthe portion of the oxidized fuel fluid into the opening comprisesflowing the oxidized fuel fluid through a perforated conduit disposed inthe opening, the method further comprising removing an exhaust fluidthrough the opening.
 4155. The method of claim 4152, further comprisinginitiating oxidation of the fuel fluid in the heater with a flame. 4156.The method of claim 4152, further comprising removing the oxidized fuelfluid through the conduit.
 4157. The method of claim 4152, furthercomprising removing the oxidized fuel fluid through the conduit andproviding the removed oxidized fuel fluid to at least one additionalheater disposed in the formation.
 4158. The method of claim 4152,wherein the conduit comprises an insulator disposed on a surface of theconduit, the method further comprising tapering a thickness of theinsulator such that heat is allowed to transfer substantially uniformlyalong a length of the conduit.
 4159. The method of claim 4152, whereinthe electric heater is an insulated conductor.
 4160. The method of claim4152, wherein the electric heater is a conductor disposed in theconduit.
 4161. The method of claim 4152, wherein the electric heater isan elongated conductive member.
 4162. The method of claim 4152, whereinthe hydrocarbon containing formation comprises a coal formation. 4163.The method of claim 4152, wherein the hydrocarbon containing formationcomprises an oil shale formation.
 4164. The method of claim 4152,wherein the hydrocarbon containing formation comprises a heavy oiland/or tar containing permeable formation.
 4165. The method of claim4152, wherein the hydrocarbon containing formation comprises a heavy oiland/or tar containing impermeable formation.
 4166. A system configuredto heat a hydrocarbon containing formation, comprising: one or moreheaters disposed within one or more open wellbores in the formation,wherein the one or more heaters are configured to provide heat to atleast a portion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the one or more heaters to aselected section of the formation during use.
 4167. The system of claim4166, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.4168. The system of claim 4166, wherein the one or more heaters compriseelectrical heaters.
 4169. The system of claim 4166, wherein the one ormore heaters comprise surface burners.
 4170. The system of claim 4166,wherein the one or more heaters comprise flameless distributedcombustors.
 4171. The system of claim 4166, wherein the one or moreheaters comprise natural distributed combustors.
 4172. The system ofclaim 4166, wherein the one or more open wellbores comprise a diameterof at least approximately 5 cm.
 4173. The system of claim 4166, furthercomprising an overburden casing coupled to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation.
 4174. The system of claim 4166, furthercomprising an overburden casing coupled to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 4175. The system of claim 4166, further comprising an overburdencasing coupled to at least one of the one or more open wellbores,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 4176. The system of claim 4166, further comprising an overburdencasing coupled to at least one of the one or more open wellbores,wherein the overburden casing is disposed in an overburden of theformation, and wherein a packing material is disposed at a junction ofthe overburden casing and the at least one of the one or more openwellbores.
 4177. The system of claim 4166, further comprising anoverburden casing coupled to at least one of the one or more openwellbores, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the at least one of the one or more openwellbores, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between at least one of the one ormore open wellbores and the overburden casing during use.
 4178. Thesystem of claim 4166, further comprising an overburden casing coupled toat least one of the one or more open wellbores, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the atleast one of the one or more open wellbores, and wherein the packingmaterial comprises cement.
 4179. The system of claim 4166, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.4180. The system of claim 4166, further comprising a valve coupled to atleast one of the one or more heaters configured to control pressurewithin at least a majority of the selected section of the formation.4181. The system of claim 4166, further comprising a valve coupled to aproduction well configured to control a pressure within at least amajority of the selected section of the formation.
 4182. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least one portion of theformation, wherein the one or more heaters are disposed within one ormore open wellbores in the formation; allowing the heat to transfer fromthe one or more heaters to a selected section of the formation; andproducing a mixture from the formation.
 4183. The method of claim 4182,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.4184. The method of claim 4182, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range with a lower pyrolysis temperature of about250° C. and an upper pyrolysis temperature of about 400° C.
 4185. Themethod of claim 4182, wherein the one or more heaters compriseelectrical heaters.
 4186. The method of claim 4182, wherein the one ormore heaters comprise surface burners.
 4187. The method of claim 4182,wherein the one or more heaters comprise flameless distributedcombustors.
 4188. The method of claim 4182, wherein the one or moreheaters comprise natural distributed combustors.
 4189. The method ofclaim 4182, wherein the one or more heaters are suspended within the oneor more open wellbores.
 4190. The method of claim 4182, wherein a tubeis disposed in at least one of the one or more open wellbores proximateto the heater, the method further comprising flowing a substantiallyconstant amount of fluid into at least one of the one or more openwellbores through critical flow orifices in the tube.
 4191. The methodof claim 4182, wherein a perforated tube is disposed in at least one ofthe one or more open wellbores proximate to the heater, the methodfurther comprising flowing a corrosion inhibiting fluid into at leastone of the open wellbores through the perforated tube.
 4192. The methodof claim 4182, further comprising coupling an overburden casing to atleast one of the one or more open wellbores, wherein the overburdencasing is disposed in an overburden of the formation.
 4193. The methodof claim 4182, further comprising coupling an overburden casing to atleast one of the one or more open wellbores, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4194. The method of claim 4182,further comprising coupling an overburden casing to at least one of theone or more open wellbores, wherein the overburden casing is disposed inan overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4195. The method of claim 4182, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the at least one of the oneor more open wellbores.
 4196. The method of claim 4182, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the method further comprisesinhibiting a flow of fluid between the at least one of the one or moreopen wellbores and the overburden casing with a packing material. 4197.The method of claim 4182, further comprising heating at least theportion of the formation to substantially pyrolyze at least some of thehydrocarbons within the formation.
 4198. The method of claim 4182,further comprising controlling a pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 4199. The method of claim 4182,further comprising controlling a pressure with the wellbore.
 4200. Themethod of claim 4182, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to at least one of the one or more heaters.
 4201. Themethod of claim 4182, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to a production well located in the formation.
 4202. Themethod of claim 4182, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 4203. The method of claim 4182, whereinproviding heat from the one or more heaters to at least the portion offormation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heaters, wherein the formationhas an average heat capacity(C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 4204. The method of claim 4182, wherein allowingthe heat to transfer from the one or more heaters to the selectedsection comprises transferring heat substantially by conduction. 4205.The method of claim 4182, wherein providing heat from the one or moreheaters comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 4206. The method of claim 4182, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 4207. The method of claim 4182, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4208. The method of claim 4182, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4209. The method of claim 4182,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 4210. The method of claim4182, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 4211. The method ofclaim 4182, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 4212. Themethod of claim 4182, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4213. Themethod of claim 4182, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 4214. Themethod of claim 4182, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4215. The method ofclaim 4182, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4216. The method of claim 4182, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 4217. The methodof claim 4182, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4218. The method of claim4182, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen, andwherein the hydrogen is greater than about 10% by volume of thenon-condensable component and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 4219. The method ofclaim 4182, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.4220. The method of claim 4182, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 4221.The method of claim 4182, further comprising controlling a pressurewithin at least a majority of the selected section of the formation.4222. The method of claim 4182, further comprising controlling apressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 4223. The method of claim 4182, further comprising controllingformation conditions such that the produced mixture comprises a partialpressure of H₂ within the mixture greater than about 0.5 bars.
 4224. Themethod of claim 4223, wherein the partial pressure of H₂ is measuredwhen the mixture is at a production well.
 4225. The method of claim4182, wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 4226. Themethod of claim 4182, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 4227. The method of claim4182, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 4228. The method of claim4182, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 4229. The method of claim 4182, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 4230. Themethod of claim 4182, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 4231. The method of claim 4182, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 4232. Themethod of claim 4182, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatersare disposed in the formation for the production well.
 4233. The methodof claim 4182, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 4234. Themethod of claim 4182, further comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,wherein the unit of heaters comprises a triangular pattern, and whereina plurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 4235. The method of claim 4182,further comprising separating the produced mixture into a gas stream anda liquid stream.
 4236. The method of claim 4182, further comprisingseparating the produced mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 4237. The method of claim 4182, wherein the producedmixture comprises H₂S, the method further comprising separating aportion of the H₂S from non-condensable hydrocarbons.
 4238. The methodof claim 4182, wherein the produced mixture comprises CO₂, the methodfurther comprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 4239. The method of claim 4182, wherein the mixture isproduced from a production well, wherein the heating is controlled suchthat the mixture can be produced from the formation as a vapor. 4240.The method of claim 4182, wherein the mixture is produced from aproduction well, the method further comprising heating a wellbore of theproduction well to inhibit condensation of the mixture within thewellbore.
 4241. The method of claim 4182, wherein the mixture isproduced from a production well, wherein a wellbore of the productionwell comprises a heater element configured to heat the formationadjacent to the wellbore, and further comprising heating the formationwith the heater element to produce the mixture, wherein the mixturecomprises a large non-condensable hydrocarbon gas component and H₂.4242. The method of claim 4182, wherein the selected section is heatedto a minimum pyrolysis temperature of about 270° C.
 4243. The method ofclaim 4182, further comprising maintaining the pressure within theformation above about 2.0 bars absolute to inhibit production of fluidshaving carbon numbers above
 25. 4244. The method of claim 4182, furthercomprising controlling pressure within the formation in a range fromabout atmospheric pressure to about 100 bar, as measured at a wellheadof a production well, to control an amount of condensable hydrocarbonswithin the produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons, and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 4245.The method of claim 4182, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bar, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 4246. A mixtureproduced from a portion of a hydrocarbon containing formation, themixture comprising: an olefin content of less than about 10% by weight;and an average carbon number less than about
 35. 4247. The mixture ofclaim 4246, further comprising an average carbon number less than about30.
 4248. The mixture of claim 4246, further comprising an averagecarbon number less than about
 25. 4249. The mixture of claim 4246,further comprising: non-condensable hydrocarbons comprising hydrocarbonshaving carbon numbers of less than 5; and wherein a weight ratio of thehydrocarbons having carbon numbers from 2 through 4, to methane, in themixture is greater than approximately
 1. 4250. The mixture of claim4246, further comprising condensable hydrocarbons, wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4251. The mixture of claim 4246, further comprising ammonia,wherein greater than about 0.05% by weight of the produced mixture isammonia.
 4252. The mixture of claim 4246, further comprising condensablehydrocarbons, wherein an olefin content of the condensable hydrocarbonsis greater than about 0.1% by weight of the condensable hydrocarbons,and wherein the olefin content of the condensable hydrocarbons is lessthan about 15% by weight of the condensable hydrocarbons.
 4253. Themixture of claim 4246, further comprising condensable hydrocarbons,wherein less than about 15% by weight of the condensable hydrocarbonshave a carbon number greater than about
 25. 4254. The mixture of claim4253, wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen, wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4255. The mixture of claim 4246, furthercomprising condensable hydrocarbons, wherein greater than about 20% byweight of the condensable hydrocarbons are aromatic compounds.
 4256. Themixture of claim 4246, further comprising: non-condensable hydrocarbonscomprising hydrocarbons having carbon numbers of less than about 5,wherein a weight ratio of the hydrocarbons having carbon number from 2through 4, to methane, in the mixture is greater than approximately 1;wherein the non-condensable hydrocarbons further comprise H₂, whereingreater than about 15% by weight of the non-condensable hydrocarbonscomprises H₂; and condensable hydrocarbons, comprising: oxygenatedhydrocarbons, wherein greater than about 1.5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons; and aromaticcompounds, wherein greater than about 20% by weight of the condensablehydrocarbons comprises aromatic compounds.
 4257. The mixture of claim4246, further comprising: condensable hydrocarbons, wherein less thanabout 5% by weight of the condensable hydrocarbons compriseshydrocarbons having a carbon number greater than about 25; wherein thecondensable hydrocarbons further comprise: oxygenated hydrocarbons,wherein greater than about 5% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons; and aromatic compounds, whereingreater than about 30% by weight of the condensable hydrocarbonscomprises aromatic compounds; and non-condensable hydrocarbonscomprising H₂, wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂.
 4258. The mixture of claim4246, further comprising condensable hydrocarbons, comprising: olefins,wherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons comprises olefins; and asphaltenes, wherein less than about0.1% by weight of the condensable hydrocarbons comprises asphaltenes.4259. The mixture of claim 4258, further comprising oxygenatedhydrocarbons, wherein less than about 15% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4260. The mixture ofclaim 4246, further comprising condensable hydrocarbons, comprising:olefins, wherein about 0.1% by weight to about 2% by weight of thecondensable hydrocarbons comprises olefins; and multi-ring aromatics,wherein less than about 2% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4261. Themixture of claim 4246, further comprising oxygenated hydrocarbons,wherein greater than about 25% by weight of the condensable hydrocarbonscomprises oxygenated hydrocarbons.
 4262. The mixture of claim 4246,further comprising: non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, wherein greater than about 10%by weight of the non-condensable hydrocarbons comprises H₂; ammonia,wherein greater than about 0.5% by weight of the mixture comprisesammonia; and hydrocarbons, wherein a weight ratio of hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.4.
 4263. A mixture produced from a portion of a hydrocarbon containingformation, the mixture, comprising: non-condensable hydrocarbonscomprising hydrocarbons having carbon numbers of less than 5; andwherein a weight ratio of the hydrocarbons having carbon numbers from 2through 4, to methane, in the mixture is greater than approximately 1.4264. The mixture of claim 4263, further comprising condensablehydrocarbons, wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 4265. The mixture of claim 4263,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4266. The mixture ofclaim 4263, further comprising condensable hydrocarbons, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4267. The mixture of claim 4263,further comprising condensable hydrocarbons, wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4268. The mixture of claim 4263, furthercomprising condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4269. The mixture of claim 4263, further comprising condensablehydrocarbons, wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4270. Themixture of claim 4263, further comprising condensable hydrocarbons,wherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4271. The mixture of claim 4263, furthercomprising condensable hydrocarbons, wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 4272. The mixture of claim 4263, furthercomprising condensable hydrocarbons, wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 4273. Themixture of claim 4263, further comprising condensable hydrocarbons,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise cycloalkanes.
 4274. The mixture of claim 4263,wherein the non-condensable hydrocarbons further comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable hydrocarbons, and wherein the hydrogen is less thanabout 80% by volume of the non-condensable hydrocarbons.
 4275. Themixture of claim 4263, further comprising ammonia, wherein greater thanabout 0.05% by weight of the produced mixture is ammonia.
 4276. Themixture of claim 4263, further comprising ammonia, wherein the ammoniais used to produce fertilizer.
 4277. The mixture of claim 4263, furthercomprising condensable hydrocarbons, wherein less than about 15 weight %of the condensable hydrocarbons have a carbon number greater thanapproximately
 25. 4278. The mixture of claim 4263, further comprisingcondensable hydrocarbons, wherein the condensable hydrocarbons compriseolefins, and wherein about 0.1% to about 5% by weight of the condensablehydrocarbons comprises olefins.
 4279. The mixture of claim 4263, furthercomprising condensable hydrocarbons, wherein the condensablehydrocarbons comprises olefins, and wherein about 0.1% to about 2.5% byweight of the condensable hydrocarbons comprises olefins.
 4280. Themixture of claim 4263, further comprising condensable hydrocarbons,wherein the condensable hydrocarbons comprise oxygenated hydrocarbons,and wherein greater than about 5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4281. The mixture ofclaim 4263, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4282. Themixture of claim 4263, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, and whereingreater than about 15% by weight of the non-condensable hydrocarbonscomprises H₂.
 4283. The mixture of claim 4263, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater than about 0.3.
 4284. A mixture produced from a portion of ahydrocarbon containing formation, the mixture comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than 5, wherein a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, is greater thanapproximately 1; and condensable hydrocarbons comprising oxygenatedhydrocarbons, wherein greater than about 5% by weight of the condensablecomponent comprises oxygenated hydrocarbons.
 4285. The mixture of claim4284, wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 4286. The mixture of claim 4284,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4287. The mixture ofclaim 4284, wherein less than about 1% by weight, when calculated on anatomic basis, of the condensable hydrocarbons is nitrogen.
 4288. Themixture of claim 4284, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4289. The mixture of claim 4284, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4290. The mixture of claim 4284, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4291. The mixture of claim 4284, whereingreater than about 20% by weight of the condensable hydrocarbons arearomatic compounds.
 4292. The mixture of claim 4284, wherein less thanabout 5% by weight of the condensable hydrocarbons comprises multi-ringaromatics with more than two rings.
 4293. The mixture of claim 4284,wherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 4294. The mixture of claim 4284, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4295. The mixture of claim 4284, wherein thenon-condensable hydrocarbons comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable hydrocarbons,and wherein the hydrogen is less than about 80% by volume of thenon-condensable hydrocarbons.
 4296. The mixture of claim 4284, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 4297. The mixture ofclaim 4284, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 4298. The mixture of claim4284, wherein less than about 5 weight % of the condensable hydrocarbonsin the mixture have a carbon number greater than approximately
 25. 4299.The mixture of claim 4284, wherein the condensable hydrocarbons furthercomprise olefins, and wherein about 0.1% to about 5% by weight of thecondensable hydrocarbons comprises olefins.
 4300. The mixture of claim4284, wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% to about 2.5% by weight of the condensablehydrocarbons comprises olefins.
 4301. The mixture of claim 4284, whereinthe non-condensable hydrocarbons further comprise H₂, wherein greaterthan about 5% by weight of the mixture comprises H₂.
 4302. The mixtureof claim 4284, wherein the non-condensable hydrocarbons further compriseH₂, wherein greater than about 15% by weight of the mixture comprisesH₂.
 4303. The mixture of claim 4284, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater than about 0.3.
 4304. A mixture produced from a portion of ahydrocarbon containing formation, the mixture comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than 5, wherein a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, is greater thanapproximately 1; condensable hydrocarbons; wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons comprises nitrogen; wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbonscomprises oxygen; and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons comprisessulfur.
 4305. The mixture of claim 4304, further comprising ammonia,wherein greater than about 0.05% by weight of the produced mixture isammonia.
 4306. The mixture of claim 4304, wherein less than about 5weight % of the condensable hydrocarbons have a carbon number greaterthan approximately
 25. 4307. The mixture of claim 4304, wherein thecondensable hydrocarbons comprise olefins, and wherein about 0.1% byweight to about 15% by weight of the condensable hydrocarbons areolefins.
 4308. The mixture of claim 4304, wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 4309. The mixture of claim 4304, wherein about 5%by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4310. The mixture of claim 4304, whereingreater than about 20% by weight of the condensable hydrocarbons arearomatic compounds.
 4311. The mixture of claim 4304, wherein less thanabout 5% by weight of the condensable hydrocarbons comprises multi-ringaromatics with more than two rings.
 4312. The mixture of claim 4304,wherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 4313. The mixture of claim 4304, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4314. The mixture of claim 4304, wherein thenon-condensable hydrocarbons comprises hydrogen, and wherein thehydrogen is greater than about 10% by volume of the non-condensablehydrocarbons and wherein the hydrogen is less than about 80% by volumeof the non-condensable hydrocarbons.
 4315. The mixture of claim 4304,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4316. The mixture of claim4304, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4317. The mixture of claim 4304, wherein thecondensable hydrocarbons comprises oxygenated hydrocarbons, and whereingreater than about 5% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4318. The mixture of claim 4304, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4319. Themixture of claim 4304, wherein the non-condensable hydrocarbons compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4320. The mixture of claim 4304, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater, than about 0.3.
 4321. A mixture produced from a portion of ahydrocarbon containing formation, the mixture comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than 5, wherein a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, is greater thanapproximately 1; ammonia, wherein greater than about 0.5% by weight ofthe mixture comprises ammonia; and condensable hydrocarbons comprisingoxygenated hydrocarbons, wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4322. Themixture of claim 4321, wherein the condensable hydrocarbons furthercomprise olefins, and wherein about 0.1% by weight to about 15% byweight of the condensable hydrocarbons are olefins.
 4323. The mixture ofclaim 4321, wherein the non-condensable hydrocarbons further compriseethene and ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4324. The mixture of claim 4321, wherein the condensable hydrocarbonsfurther comprise nitrogen containing compounds, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4325. The mixture of claim 4321,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4326. Themixture of claim 4321, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4327. The mixture of claim 4321, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4328. The mixture of claim4321, wherein the condensable hydrocarbons further comprise aromaticcompounds, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4329. The mixture ofclaim 4321, wherein the condensable hydrocarbons further comprisemulti-aromatic rings, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4330. The mixture of claim 4321, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4331.The mixture of claim 4321, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4332. Themixture of claim 4321, wherein the non-condensable hydrocarbons furthercomprise hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable hydrocarbons, and wherein the hydrogen isless than about 80% by volume of the non-condensable hydrocarbons. 4333.The mixture of claim 4321, wherein the produced mixture furthercomprises ammonia, and wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4334. The mixture of claim 4321, whereinthe produced mixture further comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 4335. The mixture of claim 4321, whereinthe condensable hydrocarbons comprise hydrocarbons having a carbonnumber of greater than approximately 25, and wherein less than about 15weight % of the hydrocarbons in the mixture have a carbon number greaterthan approximately
 25. 4336. The mixture of claim 4321, wherein thenon-condensable hydrocarbons further comprise H₂, and wherein greaterthan about 5% by weight of the mixture comprises H₂.
 4337. The mixtureof claim 4321, wherein the non-condensable hydrocarbons further compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4338. The mixture of claim 4321, wherein thenon-condensable hydrocarbons further comprise hydrocarbons having carbonnumbers of greater than 2, wherein a weight ratio of hydrocarbons havingcarbon numbers greater than 2, to methane, is greater than about 0.3.4339. A mixture produced from a portion of a hydrocarbon containingformation, the mixture comprising: non-condensable hydrocarbonscomprising hydrocarbons having carbon numbers of less than 5, wherein aweight ratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 1; and condensable hydrocarbonscomprising olefins, wherein less than about 10% by weight of thecondensable hydrocarbons comprises olefins.
 4340. The mixture of claim4339, wherein the non-condensable hydrocarbons further comprise etheneand ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4341. The mixture of claim 4339, wherein the condensable hydrocarbonsfurther comprise nitrogen containing compounds, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4342. The mixture of claim 4339,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4343. Themixture of claim 4339, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4344. The mixture of claim 4339, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4345. The mixture of claim4339, wherein the condensable hydrocarbons further comprise aromaticcompounds, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4346. The mixture ofclaim 4339, wherein the condensable hydrocarbons further comprisemulti-ring aromatics, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4347. The mixture of claim 4339, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4348.The mixture of claim 4339, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4349. Themixture of claim 4339, wherein the non-condensable hydrocarbons furthercomprise hydrogen, and wherein the hydrogen is greater than about 10% byvolume of the non-condensable hydrocarbons and wherein the hydrogen isless than about 80% by volume of the non-condensable hydrocarbons. 4350.The mixture of claim 4339, wherein the produced mixture furthercomprises ammonia, and wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4351. The mixture of claim 4339, whereinthe produced mixture further comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 4352. The mixture of claim 4339, whereinthe condensable hydrocarbons further comprise hydrocarbons having acarbon number of greater than approximately 25, and wherein less thanabout 15% by weight of the hydrocarbons have a carbon number greaterthan approximately
 25. 4353. The mixture of claim 4339, wherein about0.1% to about 5% by weight of the condensable component comprisesolefins.
 4354. The mixture of claim 4339, wherein about 0.1% to about 2%by weight of the condensable component comprises olefins.
 4355. Themixture of claim 4339, wherein the condensable hydrocarbons furthercomprise oxygenated hydrocarbons, and wherein greater than about 5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4356. The mixture of claim 4339, wherein the condensablehydrocarbons further comprise oxygenated hydrocarbons, and whereingreater than about 25% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4357. The mixture of claim 4339, wherein thenon-condensable hydrocarbons further comprise H₂, and wherein greaterthan about 5% by weight of the non-condensable hydrocarbons comprisesH₂.
 4358. The mixture of claim 4339, wherein the non-condensablehydrocarbons further comprise H₂, and wherein greater than about 15% byweight of the non-condensable hydrocarbons comprises H₂.
 4359. Themixture of claim 4339, wherein a weight ratio of hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.3.
 4360. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about15 weight % of the condensable hydrocarbons have a carbon number greaterthan 25; and wherein the condensable hydrocarbons comprise oxygenatedhydrocarbons, and wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4361. Themixture of claim 4360, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise hydrocarbons havingcarbon numbers of less than 5, and wherein a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, isgreater than approximately
 1. 4362. The mixture of claim 4360, whereinthe condensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4363. The mixture of claim 4360, further comprisingnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons ranges from about 0.001 to about0.15.
 4364. The mixture of claim 4360, wherein the condensablehydrocarbons further comprise nitrogen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4365. The mixture of claim 4360,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4366. Themixture of claim 4360, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4367. The mixture of claim 4360, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4368. The mixture of claim4360, wherein the condensable hydrocarbons further comprise aromaticcompounds, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4369. The mixture ofclaim 4360, wherein the condensable hydrocarbons further comprisemulti-ring aromatics, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4370. The mixture of claim 4360, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4371.The mixture of claim 4360, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4372. Themixture of claim 4360, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise hydrogen, and whereinthe hydrogen is greater than about 10% by volume of the non-condensablehydrocarbons and wherein the hydrogen is less than about 80% by volumeof the non-condensable hydrocarbons.
 4373. The mixture of claim 4360,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4374. The mixture of claim4360, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4375. The mixture of claim 4360, wherein thecondensable hydrocarbons further comprises olefins, and wherein lessthan about 10% by weight of the condensable hydrocarbons comprisesolefins.
 4376. The mixture of claim 4360, wherein the condensablehydrocarbons further comprises olefins, and wherein about 0.1% to about5% by weight of the condensable hydrocarbons comprises olefins. 4377.The mixture of claim 4360, wherein the condensable hydrocarbons furthercomprises olefins, and wherein about 0.1% to about 2% by weight of thecondensable hydrocarbons comprises olefins.
 4378. The mixture of claim4360, wherein the condensable hydrocarbons further comprises oxygenatedhydrocarbons, and wherein greater than about 5% by weight of thecondensable hydrocarbons comprises the oxygenated hydrocarbon.
 4379. Themixture of claim 4360, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, wherein greaterthan about 5% by weight of the non-condensable hydrocarbons comprisesH₂.
 4380. The mixture of claim 4360, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂,wherein greater than about 15% by weight of the non-condensablehydrocarbons comprises H₂.
 4381. The mixture of claim 4360, wherein aweight ratio of hydrocarbons having greater than about 2 carbon atoms,to methane, is greater than about 0.3.
 4382. A mixture produced from aportion of a hydrocarbon containing formation, comprising: condensablehydrocarbons, wherein less than about 15% by weight of the condensablehydrocarbons have a carbon number greater than about 25; wherein lessthan about 1% by weight of the condensable hydrocarbons, when calculatedon an atomic basis, is nitrogen; wherein less than about 1% by weight ofthe condensable hydrocarbons, when calculated on an atomic basis, isoxygen; and wherein less than about 1% by weight of the condensablehydrocarbons, when calculated on an atomic basis, is sulfur.
 4383. Themixture of claim 4382, further comprising non-condensable hydrocarbons,wherein the non-condensable component comprises hydrocarbons havingcarbon numbers of less than 5, and wherein a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, isgreater than approximately
 1. 4384. The mixture of claim 4382, whereinthe condensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4385. The mixture of claim 4382, further comprisingnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4386. The mixture of claim 4382, wherein the condensablehydrocarbons further comprise oxygen containing compounds, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4387. The mixture of claim 4382, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4388. The mixture of claim 4382, wherein thecondensable hydrocarbons further comprise multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4389. Themixture of claim 4382, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4390. The mixture of claim4382, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4391. The mixture ofclaim 4382, further comprising non-condensable hydrocarbons, and whereinthe non-condensable hydrocarbons comprise hydrogen, and wherein greaterthan about 10% by volume and less than about 80% by volume of thenon-condensable component comprises hydrogen.
 4392. The mixture of claim4382, further comprising ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 4393. The mixture of claim4382, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4394. The mixture of claim 4382, wherein thecondensable component further comprises olefins, and wherein about 0.1%to about 5% by weight of the condensable component comprises olefins.4395. The mixture of claim 4382, wherein the condensable componentfurther comprises olefins, and wherein about 0.1% to about 2.5% byweight of the condensable component comprises olefins.
 4396. The mixtureof claim 4382, wherein the condensable hydrocarbons further compriseoxygenated hydrocarbons, and wherein greater than about 5% by weight ofthe condensable hydrocarbons comprises oxygenated hydrocarbons. 4397.The mixture of claim 4382, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, andwherein greater than about 5% by weight of the non-condensablehydrocarbons comprises H₂.
 4398. The mixture of claim 4382, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 15% by weightof the non-condensable hydrocarbons comprises H₂.
 4399. The mixture ofclaim 4382, further comprising non-condensable hydrocarbons, wherein aweight ratio of compounds within the non-condensable hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.3.
 4400. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about15% by weight of the condensable hydrocarbons have a carbon numbergreater than 20; and wherein the condensable hydrocarbons compriseolefins, wherein an olefin content of the condensable component is lessthan about 10% by weight of the condensable component.
 4401. The mixtureof claim 4400, further comprising non-condensable hydrocarbons, whereinthe non-condensable hydrocarbons comprise hydrocarbons having carbonnumbers of less than 5, and wherein a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, is greater thanapproximately
 1. 4402. The mixture of claim 4400, wherein thecondensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4403. The mixture of claim 4400, further comprisingnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4404. The mixture of claim 4400, wherein the condensablehydrocarbons further comprise nitrogen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4405. The mixture of claim 4400,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4406. Themixture of claim 4400, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4407. The mixture of claim 4400, wherein thecondensable hydrocarbons, wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4408. The mixture of claim 4400, wherein the condensable hydrocarbonsfurther comprise aromatic compounds, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 4409.The mixture of claim 4400, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4410. The mixture of claim 4400, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4411.The mixture of claim 4400, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4412. Themixture of claim 4400, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprises hydrogen, and whereinthe hydrogen is about 10% by volume to about 80% by volume of thenon-condensable hydrocarbons.
 4413. The mixture of claim 4400, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4414. The mixture of claim 4400, furthercomprising ammonia, and wherein the ammonia is used to producefertilizer.
 4415. The mixture of claim 4400, wherein about 0.1% to about5% by weight of the condensable component comprises olefins.
 4416. Themixture of claim 4400, wherein about 0.1% to about 2% by weight of thecondensable component comprises olefins.
 4417. The mixture of claim4400, wherein the condensable component further comprises oxygenatedhydrocarbons, and wherein greater than about 1.5% by weight of thecondensable component comprises oxygenated hydrocarbons.
 4418. Themixture of claim 4400, wherein the condensable component furthercomprises oxygenated hydrocarbons, and wherein greater than about 25% byweight of the condensable component comprises oxygenated hydrocarbons.4419. The mixture of claim 4400, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, andwherein greater than about 5% by weight of the non-condensablehydrocarbons comprises H₂.
 4420. The mixture of claim 4400, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 15% by weightof the non-condensable hydrocarbons comprises H₂.
 4421. The mixture ofclaim 4400, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrocarbons having carbon numbersof less than 5, and wherein a weight ratio of hydrocarbons having carbonnumbers from 2 through 4, to methane, is greater than approximately 0.3.4422. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about5% by weight of the condensable hydrocarbons comprises hydrocarbonshaving a carbon number greater than about 25; and wherein thecondensable hydrocarbons further comprise aromatic compounds, whereinmore than about 20% by weight of the condensable hydrocarbons comprisesaromatic compounds.
 4423. The mixture of claim 4422, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise hydrocarbons having carbon numbers of less than 5, and whereina weight ratio of hydrocarbons having carbon numbers from 2 through 4,to methane, is greater than approximately
 1. 4424. The mixture of claim4422, wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4425. The mixture of claim 4422, furthercomprising non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4426. The mixture of claim 4422, wherein the condensablehydrocarbons further comprise nitrogen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4427. The mixture of claim 4422,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4428. Themixture of claim 4422, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4429. The mixture of claim 4422, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4430. The mixture of claim4422, wherein the condensable hydrocarbons further comprise multi-ringaromatics, and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4431. The mixture of claim 4422, wherein the condensable hydrocarbonsfurther comprise asphaltenes, and wherein less than about 0.3% by weightof the condensable hydrocarbons are asphaltenes.
 4432. The mixture ofclaim 4422, wherein the condensable hydrocarbons comprise cycloalkanes,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4433. The mixture of claim 4422, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise hydrogen, and wherein the hydrogen is greater thanabout 10% by volume and less than about 80% by volume of thenon-condensable hydrocarbons.
 4434. The mixture of claim 4422, furthercomprising ammonia, and wherein greater than about 0.05% by weight ofthe produced mixture is ammonia.
 4435. The mixture of claim 4422,further comprising ammonia, and wherein the ammonia is used to producefertilizer.
 4436. The mixture of claim 4422, wherein the condensablehydrocarbons further comprise olefins, and wherein about 0.1% to about5% by weight of the condensable hydrocarbons comprises olefins. 4437.The mixture of claim 4422, wherein the condensable hydrocarbons furthercomprises olefins, and wherein about 0.1% to about 2% by weight of thecondensable hydrocarbons comprises olefins.
 4438. The mixture of claim4422, wherein the condensable hydrocarbons further comprises multi-ringaromatic compounds, and wherein less than about 2% by weight of thecondensable hydrocarbons comprises multi-ring aromatic compounds. 4439.The mixture of claim 4422, wherein the condensable hydrocarbonscomprises oxygenated hydrocarbons, and wherein greater than about 1.5%by weight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4440. The mixture of claim 4422, wherein the condensablehydrocarbons comprises oxygenated hydrocarbons, and wherein greater thanabout 25% by weight of the condensable component comprises oxygenatedhydrocarbons.
 4441. The mixture of claim 4422, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise H₂, and wherein greater than about 5% by weight of thenon-condensable hydrocarbons comprises H₂.
 4442. The mixture of claim4422, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4443.The mixture of claim 4422, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons compriseshydrocarbons having carbon numbers of less than 5, and wherein a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 0.3.
 4444. A mixture producedfrom a portion of a hydrocarbon containing formation, comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than about 5, wherein a weight ratio of the hydrocarbonshaving carbon number from 2 through 4, to methane, in the mixture isgreater than approximately 1; wherein the non-condensable hydrocarbonsfurther comprise H₂, wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂; and condensable hydrocarbons,comprising: oxygenated hydrocarbons, wherein greater than about 1.5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons; olefins, wherein less than about 10% by weight of thecondensable hydrocarbons comprises olefins; and aromatic compounds,wherein greater than about 20% by weight of the condensable hydrocarbonscomprises aromatic compounds.
 4445. The mixture of claim 4444, whereinthe non-condensable hydrocarbons further comprise ethene and ethane, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4446. The mixture ofclaim 4444, wherein the condensable hydrocarbons further comprisenitrogen containing compounds, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4447. The mixture of claim 4444, wherein the condensablehydrocarbons further comprise oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4448. The mixture of claim 4444,wherein the condensable hydrocarbons further comprise sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4449. Themixture of claim 4444, wherein the condensable hydrocarbons furthercomprise oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4450. The mixture of claim 4444, wherein thecondensable hydrocarbons comprise multi-ring aromatics, and wherein lessthan about 5% by weight of the condensable hydrocarbons comprisesmulti-ring aromatics with more than two rings.
 4451. The mixture ofclaim 4444, wherein the condensable hydrocarbons comprise asphaltenes,and wherein less than about 0.3% by weight of the condensablehydrocarbons are asphaltenes.
 4452. The mixture of claim 4444, whereinthe condensable hydrocarbons comprise cycloalkanes, and wherein about 5%by weight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4453. The mixture of claim 4444, wherein thenon-condensable hydrocarbons further comprises hydrogen, and whereingreater than about 10% by volume and less than about 80% by volume ofthe non-condensable hydrocarbons comprises hydrogen.
 4454. The mixtureof claim 4444, further comprising ammonia, and wherein greater thanabout 0.05% by weight of the produced mixture is ammonia.
 4455. Themixture of claim 4444, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4456. The mixture of claim 4444,wherein the condensable hydrocarbons further comprise hydrocarbonshaving a carbon number of greater than approximately 25, wherein lessthan about 15% by weight of the hydrocarbons have a carbon numbergreater than approximately
 25. 4457. The mixture of claim 4444, whereinabout 0.1% to about 5% by weight of the condensable hydrocarbonscomprises olefins.
 4458. The mixture of claim 4444, wherein about 0.1%to about 2% by weight of the condensable hydrocarbons comprises olefins.4459. The mixture of claim 4444, wherein greater than about 25% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4460. The mixture of claim 4444, wherein the mixturecomprises hydrocarbons having greater than about 2 carbon atoms, andwherein the weight ratio of hydrocarbons having greater than about 2carbon atoms to methane is greater than about 0.3.
 4461. A mixtureproduced from a portion of a hydrocarbon containing formation,comprising: condensable hydrocarbons, wherein less than about 5% byweight of the condensable hydrocarbons comprises hydrocarbons having acarbon number greater than about 25; wherein the condensablehydrocarbons further comprise: oxygenated hydrocarbons, wherein greaterthan about 5% by weight of the condensable hydrocarbons comprisesoxygenated hydrocarbons; olefins, wherein less than about 10% by weightof the condensable hydrocarbons comprises olefins; and aromaticcompounds, wherein greater than about 30% by weight of the condensablehydrocarbons comprises aromatic compounds; and non-condensablehydrocarbons comprising H₂, wherein greater than about 15% by weight ofthe non-condensable hydrocarbons comprises H₂.
 4462. The mixture ofclaim 4461, wherein the non-condensable hydrocarbons further compriseshydrocarbons having carbon numbers of less than 5, and wherein a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately
 1. 4463. The mixture of claim4461, wherein the non-condensable hydrocarbons comprise ethene andethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4464. The mixture of claim 4461, wherein the condensable hydrocarbonsfurther comprise nitrogen containing compounds, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4465. The mixture of claim 4461,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is oxygen.
 4466. Themixture of claim 4461, wherein the condensable hydrocarbons furthercomprise sulfur containing compounds, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4467. The mixture of claim 4461, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4468. The mixture of claim4461, wherein the condensable hydrocarbons further comprise multi-ringaromatics, and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4469. The mixture of claim 4461, wherein the condensable hydrocarbonsfurther comprise asphaltenes, and wherein less than about 0.3% by weightof the condensable hydrocarbons are asphaltenes.
 4470. The mixture ofclaim 4461, wherein the condensable hydrocarbons comprise cycloalkanes,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4471. The mixture of claim 4461, whereingreater than about 10% by volume and less than about 80% by volume ofthe non-condensable hydrocarbons is hydrogen.
 4472. The mixture of claim4461, further comprising ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 4473. The mixture of claim4461, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4474. The mixture of claim 4461, wherein about 0.1%to about 5% by weight of the condensable hydrocarbons comprises olefins.4475. The mixture of claim 4461, wherein about 0.1% to about 2% byweight of the condensable hydrocarbons comprises olefins.
 4476. Themixture of claim 4461, wherein the condensable hydrocarbons comprisesoxygenated hydrocarbons, and wherein greater than about 15% by weight ofthe condensable hydrocarbons comprises oxygenated hydrocarbons. 4477.The mixture of claim 4461, wherein the mixture comprises hydrocarbonshaving greater than about 2 carbon atoms, and wherein the weight ratioof hydrocarbons having greater than about 2 carbon atoms to methane isgreater than about 0.3.
 4478. A mixture of condensable hydrocarbonsproduced from a portion of a hydrocarbon containing formation,comprising: olefins, wherein about 0.1% by weight to about 15% by weightof the condensable hydrocarbons comprises olefins; oxygenatedhydrocarbons, wherein less than about 15% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons; and asphaltenes, whereinless than about 0.1% by weight of the condensable hydrocarbons comprisesasphaltenes.
 4479. The mixture of claim 4478, wherein the condensablehydrocarbons further comprises hydrocarbons having a carbon number ofgreater than approximately 25, and wherein less than about 15 weight %of the hydrocarbons in the mixture have a carbon number greater thanapproximately
 25. 4480. The mixture of claim 4478, wherein about 0.1% byweight to about 5% by weight of the condensable hydrocarbons comprisesolefins.
 4481. The mixture of claim 4478, wherein the condensablehydrocarbons further comprises non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise ethene and ethane, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4482. The mixture of claim 4478,wherein the condensable hydrocarbons further comprises nitrogencontaining compounds, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4483. The mixture of claim 4478, wherein the condensablehydrocarbons further comprises oxygen containing compounds, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4484. The mixture of claim 4478,wherein the condensable hydrocarbons further comprises sulfur containingcompounds, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4485. Themixture of claim 4478, wherein the condensable hydrocarbons furthercomprises oxygen containing compounds, wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 4486. The mixture of claim 4478, wherein thecondensable hydrocarbons further comprises aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4487. The mixture of claim 4478, wherein thecondensable hydrocarbons further comprises multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4488. Themixture of claim 4478, wherein the condensable hydrocarbons furthercomprises cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4489. Themixture of claim 4478, wherein the condensable hydrocarbons comprisesnon-condensable hydrocarbons, and wherein the non-condensablehydrocarbons comprise hydrogen, and wherein the hydrogen is greater thanabout 10% by volume of the non-condensable hydrocarbons and wherein thehydrogen is less than about 80% by volume of the non-condensablehydrocarbons.
 4490. The mixture of claim 4478, further comprisingammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 4491. The mixture of claim 4478, further comprisingammonia, and wherein the ammonia is used to produce fertilizer. 4492.The mixture of claim 4478, wherein about 0.1% by weight to about 2% byweight of the condensable hydrocarbons comprises olefins.
 4493. Amixture of condensable hydrocarbons produced from a portion of ahydrocarbon containing formation, comprising: olefins, wherein about0.1% by weight to about 2% by weight of the condensable hydrocarbonscomprises olefins; multi-ring aromatics, wherein less than about 2% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings; and oxygenated hydrocarbons, wherein greaterthan about 25% by weight of the condensable hydrocarbons comprisesoxygenated hydrocarbons.
 4494. The mixture of claim 4493, furthercomprising hydrocarbons having a carbon number of greater thanapproximately 25, wherein less than about 5 weight % of the hydrocarbonsin the mixture have a carbon number greater than approximately
 25. 4495.The mixture of claim 4493, wherein the condensable hydrocarbons furthercomprises nitrogen containing compounds, and wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4496. The mixture of claim 4493, wherein thecondensable hydrocarbons further comprises oxygen containing compounds,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is oxygen.
 4497. The mixture ofclaim 4493, wherein the condensable hydrocarbons further comprisessulfur containing compounds, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4498. The mixture of claim 4493, wherein the condensablehydrocarbons further comprises oxygen containing compounds, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4499. The mixture of claim4493, wherein the condensable hydrocarbons further comprises aromaticcompounds, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4500. The mixture ofclaim 4493, wherein the condensable hydrocarbons further comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 4501. The mixture of claim4493, wherein the condensable hydrocarbons further comprisescycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4502. The mixture ofclaim 4493, further comprising ammonia, wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 4503. The mixture of claim4493, further comprising ammonia, wherein the ammonia is used to producefertilizer.
 4504. A mixture produced from a portion of a hydrocarboncontaining formation, comprising: non-condensable hydrocarbons and H₂,wherein greater than about 10% by volume of the non-condensablehydrocarbons and H₂ comprises H₂; ammonia and water, wherein greaterthan about 0.5% by weight of the mixture comprises ammonia; andcondensable hydrocarbons.
 4505. The mixture of claim 4504, wherein thenon-condensable hydrocarbons further comprise hydrocarbons having carbonnumbers of less than 5, and wherein a weight ratio of the hydrocarbonshaving carbon numbers from 2 through 4 to methane, in the mixture isgreater than approximately
 1. 4506. The mixture of claim 4504, whereingreater than about 0.1% by weight of the condensable hydrocarbons areolefins, and wherein less than about 15% by weight of the condensablehydrocarbons are olefins.
 4507. The mixture of claim 4504, wherein thenon-condensable hydrocarbons further comprise ethene and ethane, whereina molar ratio of ethene to ethane in the non-condensable hydrocarbons isgreater than about 0.001, and wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15.
 4508. Themixture of claim 4504, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4509. The mixture of claim 4504, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4510. The mixture of claim 4504, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4511. The mixture of claim 4504,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4512. The mixture of claim4504, wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 4513. The mixture of claim 4504,wherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4514. Themixture of claim 4504, wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4515. The mixture of claim4504, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons are cycloalkanes.
 4516. The mixture of claim4504, wherein the H₂ is less than about 80% by volume of thenon-condensable hydrocarbons and H₂.
 4517. The mixture of claim 4504,wherein the condensable hydrocarbons further comprise sulfur containingcompounds.
 4518. The mixture of claim 4504, wherein the ammonia is usedto produce fertilizer.
 4519. The mixture of claim 4504, wherein lessthan about 5% of the condensable hydrocarbons have carbon numbersgreater than
 25. 4520. The mixture of claim 4504, wherein thecondensable hydrocarbons comprise olefins, wherein greater than aboutabout 0.001% by weight of the condensable hydrocarbons comprise olefins,and wherein less than about 15% by weight of the condensablehydrocarbons comprise olefins.
 4521. The mixture of claim 4504, whereinthe condensable hydrocarbons comprise olefins, wherein greater thanabout about 0.001% by weight of the condensable hydrocarbons compriseolefins, and wherein less than about 10% by weight of the condensablehydrocarbons comprise olefins.
 4522. The mixture of claim 4504, whereinthe condensable hydrocarbons comprise oxygenated hydrocarbons, andwherein greater than about 1.5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4523. The mixture ofclaim 4504, wherein the condensable hydrocarbons further comprisenitrogen containing compounds.
 4524. A method of treating a hydrocarboncontaining formation in situ comprising providing heat from three ormore heaters to at least a portion of the formation, wherein three ormore of the heaters are located in the formation in a unit of heaters,and wherein the unit of heaters comprises a triangular pattern. 4525.The method of claim 4524, wherein three or more of the heaters arelocated in the formation in a plurality of the units, and wherein theplurality of units are repeated over an area of the formation to form arepetitive pattern of units.
 4526. The method of claim 4524, whereinthree or more of the heaters are located in the formation in a pluralityof the units, wherein the plurality of units are repeated over an areaof the formation to form a repetitive pattern of units, and wherein aratio of heaters in the repetitive pattern of units to production wellsin the repetitive pattern is greater than approximately
 5. 4527. Themethod of claim 4524, wherein three or more of the heaters are locatedin the formation in a plurality of the units, wherein the plurality ofunits are repeated over an area of the formation to form a repetitivepattern of units, wherein three or more production wells are locatedwithin an area defined by the plurality of units, wherein the three ormore production wells are located in the formation in a unit ofproduction wells, and wherein the unit of production wells comprises atriangular pattern.
 4528. The method of claim 4524, wherein three ormore of the heaters are located in the formation in a plurality of theunits, wherein the plurality of units are repeated over an area of theformation to form a repetitive pattern of units, wherein three or moreinjection wells are located within an area defined by the plurality ofunits, wherein the three or more injection wells are located in theformation in a unit of injection wells, and wherein the unit ofinjection wells comprises a triangular pattern.
 4529. The method ofclaim 4524, wherein three or more of the heaters are located in theformation in a plurality of the units, wherein the plurality of unitsare repeated over an area of the formation to form a repetitive patternof units, wherein three or more production wells and three or moreinjection wells are located within an area defined by the plurality ofunits, wherein the three or more production wells are located in theformation in a unit of production wells, wherein the unit of productionwells comprises a first triangular pattern, wherein the three or moreinjection wells are located in the formation in a unit of injectionwells, wherein the unit of injection wells comprises a second triangularpattern, and wherein the first triangular pattern is substantiallydifferent than the second triangular pattern.
 4530. The method of claim4524, wherein three or more of the heaters are located in the formationin a plurality of the units, wherein the plurality of units are repeatedover an area of the formation to form a repetitive pattern of units,wherein three or more monitoring wells are located within an areadefined by the plurality of units, wherein the three or more monitoringwells are located in the formation in a unit of monitoring wells, andwherein the unit of monitoring wells comprises a triangular pattern.4531. The method of claim 4524, wherein a production well is located inan area defined by the unit of heaters.
 4532. The method of claim 4524,wherein three or more of the heaters are located in the formation in afirst unit and a second unit, wherein the first unit is adjacent to thesecond unit, and wherein the first unit is inverted with respect to thesecond unit.
 4533. The method of claim 4524, wherein a distance betweeneach of the heaters in the unit of heaters varies by less than about20%.
 4534. The method of claim 4524, wherein a distance between each ofthe heaters in the unit of heaters is approximately equal.
 4535. Themethod of claim 4524, wherein providing heat from three or more heaterscomprises substantially uniformly providing heat to at least the portionof the formation.
 4536. The method of claim 4524, wherein the heatedportion comprises a substantially uniform temperature distribution.4537. The method of claim 4524, wherein the heated portion comprises asubstantially uniform temperature distribution, and wherein a differencebetween a highest temperature in the heated portion and a lowesttemperature in the heated portion comprises less than about 200° C.4538. The method of claim 4524, wherein a temperature at an outerlateral boundary of the triangular pattern and a temperature at a centerof the triangular pattern are approximately equal.
 4539. The method ofclaim 4524, wherein a temperature at an outer lateral boundary of thetriangular pattern and a temperature at a center of the triangularpattern increase substantially linearly after an initial period of time,and wherein the initial period of time comprises less than approximately3 months.
 4540. The method of claim 4524, wherein a time required toincrease an average temperature of the heated portion to a selectedtemperature with the triangular pattern of heaters is substantially lessthan a time required to increase the average temperature of the heatedportion to the selected temperature with a hexagonal pattern of heaters,and wherein a space between each of the heaters in the triangularpattern is approximately equal to a space between each of the heaters inthe hexagonal pattern.
 4541. The method of claim 4524, wherein a timerequired to increase a temperature at a coldest point within the heatedportion to a selected temperature with the triangular pattern of heatersis substantially less than a time required to increase a temperature atthe coldest point within the heated portion to the selected temperaturewith a hexagonal pattern of heaters, and wherein a space between each ofthe heaters in the triangular pattern is approximately equal to a spacebetween each of the heaters in the hexagonal pattern.
 4542. The methodof claim 4524, wherein a time required to increase a temperature at acoldest point within the heated portion to a selected temperature withthe triangular pattern of heaters is substantially less than a timerequired to increase a temperature at the coldest point within theheated portion to the selected temperature with a hexagonal pattern ofheaters, and wherein a number of heaters per unit area in the triangularpattern is equal to the number of heaters per unit are in the hexagonalpattern of heaters.
 4543. The method of claim 4524, wherein a timerequired to increase a temperature at a coldest point within the heatedportion to a selected temperature with the triangular pattern of heatersis substantially equal to a time required to increase a temperature atthe coldest point within the heated portion to the selected temperaturewith a hexagonal pattern of heaters, and wherein a space between each ofthe heaters in the triangular pattern is approximately 5 m greater thana space between each of the heaters in the hexagonal pattern.
 4544. Themethod of claim 4524, wherein providing heat from three or more heatersto at least the portion of formation comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from three or more ofthe heaters, wherein the formation has an average heat capacity (C_(v)),and wherein heat from three or more of the heaters pyrolyzes at leastsome hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate (h) of the selected volumeis about 10° C./day.
 4545. The method of claim 4524, wherein three ormore of the heaters comprise electrical heaters.
 4546. The method ofclaim 4524, wherein three or more of the heaters comprise surfaceburners.
 4547. The method of claim 4524, wherein three or more of theheaters comprise flameless distributed combustors.
 4548. The method ofclaim 4524, wherein three or more of the heaters comprise naturaldistributed combustors.
 4549. The method of claim 4524, furthercomprising: allowing the heat to transfer from three or more of theheaters to a selected section of the formation such that heat from threeor more of the heaters pyrolyzes at least some hydrocarbons within theselected section of the formation; and producing a mixture of fluidsfrom the formation.
 4550. The method of claim 4549, further comprisingcontrolling a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 4551. The method of claim 4549, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1.0° C. per day during pyrolysis.
 4552. Themethod of claim 4549, wherein allowing the heat to transfer from threeor more of the heaters to the selected section comprises transferringheat substantially by conduction.
 4553. The method of claim 4549,wherein providing heat from three or more of the heaters to at least theportion of the formation comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/m ° C.
 4554. The method of claim4549, wherein the produced mixture comprises an API gravity of at least25°.
 4555. The method of claim 4549, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 4556.The method of claim 4549, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4557. The method of claim 4549, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4558. The method of claim 4549, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4559. The method of claim 4549,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4560. The method ofclaim 4549, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4561. Themethod of claim 4549, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4562. The method ofclaim 4549, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4563. The method of claim 4549, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.1% byweight of the condensable hydrocarbons are asphaltenes.
 4564. The methodof claim 4549, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4565. The method of claim4549, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 4566. The method ofclaim 4549, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.4567. The method of claim 4549, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 4568.The method of claim 4549, further comprising controlling formationconditions to produce a mixture of hydrocarbon fluids and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 2.0 barsabsolute.
 4569. The method of claim 4549, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 4570. Themethod of claim 4549, further comprising controlling formationconditions by recirculating a portion of hydrogen from the mixture intothe formation.
 4571. The method of claim 4549, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 4572. The method of claim 4549, furthercomprising: producing hydrogen from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 4573. The method of claim 4549, whereinallowing the heat to transfer from three or more of the heaters to theselected section of the formation comprises increasing a permeability ofa majority of the selected section to greater than about 100 millidarcy.4574. The method of claim 4549, wherein allowing the heat to transferfrom three or more of the heaters to the selected section of theformation comprises substantially uniformly increasing a permeability ofa majority of the selected section.
 4575. The method of claim 4549,further comprising controlling the heat from three or more heaters toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 4576. The method of claim 4549, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heaters are disposed in the formationfor each production well.
 4577. The method of claim 4576, wherein atleast about 20 heaters are disposed in the formation for each productionwell.
 4578. The method of claim 4549, further comprising providing heatfrom three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 4579. The method of claim 4549, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4580. A methodfor in situ production of synthesis gas from a hydrocarbon containingformation, comprising: heating a section of the formation to atemperature sufficient to allow synthesis gas generation, wherein apermeability of the section is substantially uniform and greater than apermeability of an unheated section of the formation when thetemperature sufficient to allow synthesis gas generation within theformation is achieved; providing a synthesis gas generating fluid to thesection to generate synthesis gas; and removing synthesis gas from theformation.
 4581. The method of claim 4580, wherein the permeability ofthe section is greater than about 100 millidarcy when the temperaturesufficient to allow synthesis gas generation within the formation isachieved.
 4582. The method of claim 4580, wherein the temperaturesufficient to allow synthesis gas generation ranges from approximately400° C. to approximately 1200° C.
 4583. The method of claim 4580,further comprising heating the section when providing the synthesis gasgenerating fluid to inhibit temperature decrease in the section due tosynthesis gas generation.
 4584. The method of claim 4580, whereinheating the section comprises convecting an oxidizing fluid into aportion of the section, wherein the temperature within the section isabove a temperature sufficient to support oxidation of carbon within thesection with the oxidizing fluid, and reacting the oxidizing fluid withcarbon in the section to generate heat within the section.
 4585. Themethod of claim 4584, wherein the oxidizing fluid comprises air. 4586.The method of claim 4585, wherein an amount of the oxidizing fluidconvected into the section is configured to inhibit formation of oxidesof nitrogen by maintaining a reaction temperature below a temperaturesufficient to produce oxides of nitrogen compounds.
 4587. The method ofclaim 4580, wherein heating the section comprises diffusing an oxidizingfluid to reaction zones adjacent to wellbores within the formation,oxidizing carbon within the reaction zone to generate heat, andtransferring the heat to the section.
 4588. The method of claim 4580,wherein heating the section comprises heating the section by transfer ofheat from one or more of electrical heaters.
 4589. The method of claim4580, wherein heating the section to a temperature sufficient to allowsynthesis gas generation and providing a synthesis gas generating fluidto the section comprises introducing steam into the section to heat theformation and to generate synthesis gas.
 4590. The method of claim 4580,further comprising controlling the heating of the section and provisionof the synthesis gas generating fluid to maintain a temperature withinthe section above the temperature sufficient to generate synthesis gas.4591. The method of claim 4580, further comprising: monitoring acomposition of the produced synthesis gas; and controlling heating ofthe section and provision of the synthesis gas generating fluid tomaintain the composition of the produced synthesis gas within a selectedrange.
 4592. The method of claim 4591, wherein the selected rangecomprises a ratio of H₂ to CO of about 2:1.
 4593. The method of claim4580, wherein the synthesis gas generating fluid comprises liquid water.4594. The method of claim 4580, wherein the synthesis gas generatingfluid comprises steam.
 4595. The method of claim 4580, wherein thesynthesis gas generating fluid comprises water and carbon dioxide, andwherein the carbon dioxide inhibits production of carbon dioxide fromhydrocarbon containing material within the section.
 4596. The method ofclaim 4595, wherein a portion of the carbon dioxide within the synthesisgas generating fluid comprises carbon dioxide removed from theformation.
 4597. The method of claim 4580, wherein the synthesis gasgenerating fluid comprises carbon dioxide, and wherein a portion of thecarbon dioxide reacts with carbon in the formation to generate carbonmonoxide.
 4598. The method of claim 4597, wherein a portion of thecarbon dioxide within the synthesis gas generating fluid comprisescarbon dioxide removed from the formation.
 4599. The method of claim4580, wherein providing the synthesis gas generating fluid to thesection comprises raising a water table of the formation to allow waterto flow into the section.
 4600. The method of claim 4580, wherein thesynthesis gas is removed from a producer well equipped with a heatingsource, and wherein a portion of the heating source adjacent to asynthesis gas producing zone operates at a substantially constanttemperature to promote production of the synthesis gas wherein thesynthesis gas has a selected composition.
 4601. The method of claim4600, wherein the substantially constant temperature is about 700° C.,and wherein the selected composition has a H₂ to CO ratio of about 2:1.4602. The method of claim 4580, wherein the synthesis gas generatingfluid comprises water and hydrocarbons having carbon numbers less than5, and wherein at least a portion of the hydrocarbons are subjected to areaction within the section to increase a H₂ concentration of thegenerated synthesis gas.
 4603. The method of claim 4580, wherein thesynthesis gas generating fluid comprises water and hydrocarbons havingcarbon numbers greater than 4, and wherein at least a portion of thehydrocarbons react within the section to increase an energy content ofthe synthesis gas removed from the formation.
 4604. The method of claim4580, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4605. The method of claim4580, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4606. The method of claim 4580, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4607. The method of claim 4580, further comprisingusing a portion of the synthesis gas as a combustion fuel to heat theformation.
 4608. The method of claim 4580, further comprising convertingat least a portion of the produced synthesis gas to condensablehydrocarbons using a Fischer-Tropsch synthesis process.
 4609. The methodof claim 4580, further comprising converting at least a portion of theproduced synthesis gas to methanol.
 4610. The method of claim 4580,further comprising converting at least a portion of the producedsynthesis gas to gasoline.
 4611. The method of claim 4580, furthercomprising converting at least a portion of the synthesis gas to methaneusing a catalytic methanation process.
 4612. The method of claim 4580,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 4613. The method of claim 4580,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4614. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to substantially uniformly increase apermeability of the portion and to increase a temperature of the portionto a temperature sufficient to allow synthesis gas generation; providinga synthesis gas generating fluid to at least the portion of the selectedsection, wherein the synthesis gas generating fluid comprises carbondioxide; obtaining a portion of the carbon dioxide of the synthesis gasgenerating fluid from the formation; and producing synthesis gas fromthe formation.
 4615. The method of claim 4614, wherein the temperaturesufficient to allow synthesis gas generation is within a range fromabout 400° C. to about 1200° C.
 4616. The method of claim 4614, furthercomprising using a second portion of the separated carbon dioxide as aflooding agent to produce hydrocarbon bed methane from a hydrocarboncontaining formation.
 4617. The method of claim 4616, wherein thehydrocarbon containing formation is a deep hydrocarbon containingformation over 760 m below ground surface.
 4618. The method of claim4616, wherein the hydrocarbon containing formation adsorbs some of thecarbon dioxide to sequester the carbon dioxide.
 4619. The method ofclaim 4614, further comprising using a second portion of the separatedcarbon dioxide as a flooding agent for enhanced oil recovery.
 4620. Themethod of claim 4614, wherein the synthesis gas generating fluidcomprises water and hydrocarbons having carbon numbers less than 5, andwherein at least a portion of the hydrocarbons undergo a reaction withinthe selected section to increase a H₂ concentration within the producedsynthesis gas.
 4621. The method of claim 4614, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin the selected section to increase an energy content of theproduced synthesis gas.
 4622. The method of claim 4614, furthercomprising maintaining a pressure within the formation during synthesisgas generation, and passing produced synthesis gas through a turbine togenerate electricity.
 4623. The method of claim 4614, further comprisinggenerating electricity from the synthesis gas using a fuel cell. 4624.The method of claim 4614, further comprising generating electricity fromthe synthesis gas using a fuel cell, separating carbon dioxide from afluid exiting the fuel cell, and storing a portion of the separatedcarbon dioxide within a spent portion of the formation.
 4625. The methodof claim 4614, further comprising using a portion of the synthesis gasas a combustion fuel for heating the formation.
 4626. The method ofclaim 4614, further comprising converting at least a portion of theproduced synthesis gas to condensable hydrocarbons using aFischer-Tropsch synthesis process.
 4627. The method of claim 4614,further comprising converting at least a portion of the producedsynthesis gas to methanol.
 4628. The method of claim 4614, furthercomprising converting at least a portion of the produced synthesis gasto gasoline.
 4629. The method of claim 4614, further comprisingconverting at least a portion of the synthesis gas to methane using acatalytic methanation process.
 4630. The method of claim 4614, wherein atemperature of the one or more heaters is maintained at a temperature ofless than approximately 700° C. to produce a synthesis gas having aratio of H₂ to carbon monoxide of greater than about
 2. 4631. The methodof claim 4614, wherein a temperature of the one or more heaters ismaintained at a temperature of greater than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide of lessthan about
 2. 4632. The method of claim 4614, wherein a temperature ofthe one or more heaters is maintained at a temperature of approximately700° C. to produce a synthesis gas having a ratio of H₂ to carbonmonoxide of approximately
 2. 4633. The method of claim 4614, wherein aheater of the one or more of heaters comprises an electrical heater.4634. The method of claim 4614, wherein a heater of the one or moreheaters comprises a natural distributed heater.
 4635. The method ofclaim 4614, wherein a heater of the one or more heaters comprises aflameless distributed combustor (FDC) heater, and wherein fluids areproduced from the wellbore of the FDC heater through a conduitpositioned within the wellbore.
 4636. The method of claim 4614, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 4637. The method of claim 4614,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4638. A method of in situ synthesis gas production,comprising: providing heat from one or more flameless distributedcombustor heaters to at least a first portion of a hydrocarboncontaining formation; allowing the heat to transfer from the one or moreheaters to a selected section of the formation such that the heat fromthe one or more heaters substantially uniformly increases a permeabilityof the selected section, and to raise a temperature of the selectedsection to a temperature sufficient to generate synthesis gas;introducing a synthesis gas producing fluid into the selected section togenerate synthesis gas; and removing synthesis gas from the formation.4639. The method of claim 4638, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters substantially uniformly increases a permeability of theselected section, and raises a temperature of the selected section to atemperature sufficient to generate synthesis gas.
 4640. The method ofclaim 4638, further comprising producing the synthesis gas from theformation under pressure, and generating electricity from the producedsynthesis gas by passing the produced synthesis gas through a turbine.4641. The method of claim 4638, further comprising producingpyrolyzation products from the formation when raising the temperature ofthe selected section to the temperature sufficient to generate synthesisgas.
 4642. The method of claim 4638, further comprising separating aportion of carbon dioxide from the removed synthesis gas, and storingthe carbon dioxide within a spent portion of the formation.
 4643. Themethod of claim 4638, further comprising storing carbon dioxide within aspent portion of the formation, wherein an amount of carbon dioxidestored within the spent portion of the formation is equal to or greaterthan an amount of carbon dioxide within the removed synthesis gas. 4644.The method of claim 4638, further comprising separating a portion of H₂from the removed synthesis gas; and using a portion of the separated H₂as fuel for the one or more heaters.
 4645. The method of claim 4638,further comprising using a portion of exhaust products from one or moreheaters as a portion of the synthesis gas producing fluid.
 4646. Themethod of claim 4638, further comprising using a portion of the removedsynthesis gas with a fuel cell to generate electricity.
 4647. The methodof claim 4646, wherein the fuel cell produces steam, and wherein aportion of the steam is used as a portion of the synthesis gas producingfluid.
 4648. The method of claim 4646, wherein the fuel cell producescarbon dioxide, and wherein a portion of the carbon dioxide isintroduced into the formation to react with carbon within the formationto produce carbon monoxide.
 4649. The method of claim 4646, wherein thefuel cell produces carbon dioxide, and further comprising storing anamount of carbon dioxide within a spent portion of the formation equalor greater to an amount of the carbon dioxide produced by the fuel cell.4650. The method of claim 4638, further comprising using a portion ofthe removed synthesis gas as a feed product for formation ofhydrocarbons.
 4651. The method of claim 4638, wherein the synthesis gasproducing fluid comprises hydrocarbons having carbon numbers less than5, and wherein the hydrocarbons crack within the formation to increasean amount of H₂ within the generated synthesis gas.
 4652. The method ofclaim 4638, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, and whereinthe unit of heaters comprises a triangular pattern.
 4653. The method ofclaim 4638, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, wherein theunit of heaters comprises a triangular pattern, and wherein a pluralityof the units are repeated over an area of the formation to form arepetitive pattern of units.
 4654. A method of treating a hydrocarboncontaining formation, comprising: heating a portion of the formationwith one or more electrical heaters to a temperature sufficient topyrolyze hydrocarbons within the portion; producing pyrolyzation fluidfrom the formation; separating a fuel cell feed stream from thepyrolyzation fluid; and directing the fuel cell feed stream to a fuelcell to produce electricity.
 4655. The method of claim 4654, wherein thefuel cell is a molten carbonate fuel cell.
 4656. The method of claim4654, wherein the fuel cell is a solid oxide fuel cell.
 4657. The methodof claim 4654, further comprising using a portion of the producedelectricity to power the electrical heaters.
 4658. The method of claim4654, wherein heating the portion of the formation is performed at arate sufficient to increase a permeability of the portion and to producea substantially uniform permeability within the portion.
 4659. Themethod of claim 4654, wherein the fuel cell feed stream comprises H₂ andhydrocarbons having a carbon number of less than
 5. 4660. The method ofclaim 4654, wherein the fuel cell feed stream comprises H₂ andhydrocarbons having a carbon number of less than
 3. 4661. The method ofclaim 4654, further comprising hydrogenating the pyrolyzation fluid witha portion of H₂ from the pyrolyzation fluid.
 4662. The method of claim4654, wherein the hydrogenation is done in situ by directing the H₂ intothe formation.
 4663. The method of claim 4654, wherein the hydrogenationis done in a surface unit.
 4664. The method of claim 4654, furthercomprising directing hydrocarbon fluid having carbon numbers less than 5adjacent to at least one of the electrical heaters, cracking a portionof the hydrocarbons to produce H₂, and producing a portion of thehydrogen from the formation.
 4665. The method of claim 4664, furthercomprising directing an oxidizing fluid adjacent to at least the one ofthe electrical heaters, oxidizing coke deposited on or near the at leastone of the electrical heaters with the oxidizing fluid.
 4666. The methodof claim 4654, further comprising storing CO₂ from the fuel cell withinthe formation.
 4667. The method of claim 4666, wherein the CO₂ isadsorbed to carbon material within a spent portion of the formation.4668. The method of claim 4654, further comprising cooling the portionto form a spent portion of formation.
 4669. The method of claim 4668,wherein cooling the portion comprises introducing water into the portionto produce steam, and removing steam from the formation.
 4670. Themethod of claim 4669, further comprising using a portion of the removedsteam to heat a second portion of the formation.
 4671. The method ofclaim 4669, further comprising using a portion of the removed steam as asynthesis gas producing fluid in a second portion of the formation.4672. The method of claim 4654, further comprising: heating the portionto a temperature sufficient to support generation of synthesis gas afterproduction of the pyrolyzation fluids; introducing a synthesis gasproducing fluid into the portion to generate synthesis gas; and removinga portion of the synthesis gas from the formation.
 4673. The method ofclaim 4672, further comprising producing the synthesis gas from theformation under pressure, and generating electricity from the producedsynthesis gas by passing the produced synthesis gas through a turbine.4674. The method of claim 4672, further comprising using a first portionof the removed synthesis gas as fuel cell feed.
 4675. The method ofclaim 4672, further comprising producing steam from operation of thefuel cell, and using the steam as part of the synthesis gas producingfluid.
 4676. The method of claim 4672, further comprising using carbondioxide from the fuel cell as a part of the synthesis gas producingfluid.
 4677. The method of claim 4672, further comprising using aportion of the synthesis gas to produce hydrocarbon product.
 4678. Themethod of claim 4672, further comprising cooling the portion to form aspent portion of formation.
 4679. The method of claim 4678, whereincooling the portion comprises introducing water into the portion toproduce steam, and removing steam from the formation.
 4680. The methodof claim 4679, further comprising using a portion of the removed steamto heat a second portion of the formation.
 4681. The method of claim4679, further comprising using a portion of the removed steam as asynthesis gas producing fluid in a second portion of the formation.4682. The method of claim 4654, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, and wherein the unit of heaters comprises a triangular pattern.4683. The method of claim 4654, further comprising providing heat fromthree or more heaters to at least a portion of the formation, whereinthree or more of the heaters are located in the formation in a unit ofheaters, wherein the unit of heaters comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4684. A method for insitu production of synthesis gas from a hydrocarbon containingformation, comprising: providing heat from one or more heaters to atleast a portion of the formation; allowing the heat to transfer from theone or more heaters to a selected section of the formation such that theheat from the one or more heaters pyrolyzes at least some of thehydrocarbons within the selected section of the formation; producingpyrolysis products from the formation; heating at least a portion of theselected section to a temperature sufficient to generate synthesis gas;providing a synthesis gas generating fluid to at least the portion ofthe selected section to generate synthesis gas; and producing a portionof the synthesis gas from the formation.
 4685. The method of claim 4684,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.4686. The method of claim 4684, further comprising allowing the heat totransfer from the one or more heaters to the selected section tosubstantially uniformly increase a permeability of the selected section.4687. The method of claim 4684, further comprising controlling heattransfer from the one or more heaters to produce a permeability withinthe selected section of greater than about 100 millidarcy.
 4688. Themethod of claim 4684, further comprising heating at least the portion ofthe selected section when providing the synthesis gas generating fluidto inhibit temperature decrease within the selected section duringsynthesis gas generation.
 4689. The method of claim 4684, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4690. Themethod of claim 4684, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheaters with heaters disposed in the wellbores, wherein the heaters areconfigured to raise temperatures of the zones to temperatures sufficientto support reaction of hydrocarbon containing material within the zoneswith an oxidizing fluid; introducing the oxidizing fluid to the zonessubstantially by diffusion; allowing the oxidizing fluid to react withat least a portion of the hydrocarbon containing material within thezones to produce heat in the zones; and transferring heat from the zonesto the selected section.
 4691. The method of claim 4684, wherein heatingat least the portion of the selected section to a temperature sufficientto allow synthesis gas generation comprises: introducing an oxidizingfluid into the formation through a wellbore; transporting the oxidizingfluid substantially by convection into the portion of the selectedsection, wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4692.The method of claim 4684, wherein the one or more heaters comprise oneor more electrical heaters disposed in the formation.
 4693. The methodof claim 4684, wherein the one or more heaters comprise one or moreheater wells, wherein at least one heater well comprises a conduitdisposed within the formation, and further comprising heating theconduit by flowing a hot fluid through the conduit.
 4694. The method ofclaim 4684, wherein heating at least the portion of the selected sectionto a temperature sufficient to allow synthesis gas generation andproviding a synthesis gas generating fluid to at least the portion ofthe selected section comprises introducing steam into the portion. 4695.The method of claim 4684, further comprising controlling the heating ofat least the portion of selected section and provision of the synthesisgas generating fluid to maintain a temperature within at least theportion of the selected section above the temperature sufficient togenerate synthesis gas.
 4696. The method of claim 4684, furthercomprising: monitoring a composition of the produced synthesis gas; andcontrolling heating of at least the portion of selected section andprovision of the synthesis gas generating fluid to maintain thecomposition of the produced synthesis gas within a desired range. 4697.The method of claim 4684, wherein the synthesis gas generating fluidcomprises liquid water.
 4698. The method of claim 4684, wherein thesynthesis gas generating fluid comprises steam.
 4699. The method ofclaim 4684, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4700. The method of claim4699, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4701. The method of claim 4684, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4702. The method of claim 4701, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4703. The method of claim 4684, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4704. The method of claim 4684, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4705. The method of claim 4684, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4706. The method of claim4684, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4707. The method of claim4684, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4708. The method of claim 4684, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4709. The method of claim 4684, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 4710. The method of claim 4684, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4711. The method of claim 4684, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4712. The method ofclaim 4684, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4713. The method of claim 4684,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4714. The method of claim4684, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 4715. The method of claim4684, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4716. A method for in situ production of synthesis gasfrom a hydrocarbon containing formation, comprising: heating a firstportion of the formation to pyrolyze some hydrocarbons within the firstportion; allowing the heat to transfer from one or more heaters to aselected section of the formation, pyrolyzing hydrocarbons within theselected section; producing fluid from the first portion, wherein thefluid comprises an aqueous fluid and a hydrocarbon fluid; heating asecond portion of the formation to a temperature sufficient to allowsynthesis gas generation; introducing at least a portion of the aqueousfluid to the second section after the section reaches the temperaturesufficient to allow synthesis gas generation; and producing synthesisgas from the formation.
 4717. The method of claim 4716, wherein thetemperature sufficient to allow synthesis gas generation ranges fromapproximately 400° C. to approximately 1200° C.
 4718. The method ofclaim 4716, further comprising separating ammonia within the aqueousphase from the aqueous phase prior to introduction of at least theportion of the aqueous fluid to the second section.
 4719. The method ofclaim 4716, wherein a permeability of the second portion of theformation is substantially uniform and greater than about 100 millidarcywhen the temperature sufficient to allow synthesis gas generation isachieved.
 4720. The method of claim 4716, further comprising heating thesecond portion of the formation during introduction of at least theportion of the aqueous fluid to the second section to inhibittemperature decrease in the second section due to synthesis gasgeneration.
 4721. The method of claim 4716, wherein heating the secondportion of the formation comprises convecting an oxidizing fluid into aportion of the second portion that is above a temperature sufficient tosupport oxidation of carbon within the portion with the oxidizing fluid,and reacting the oxidizing fluid with carbon in the portion to generateheat within the portion.
 4722. The method of claim 4716, wherein heatingthe second portion of the formation comprises diffusing an oxidizingfluid to reaction zones adjacent to wellbores within the formation,oxidizing carbon within the reaction zones to generate heat, andtransferring the heat to the second portion.
 4723. The method of claim4716, wherein heating the second portion of the formation comprisesheating the second section by transfer of heat from one or moreelectrical heaters.
 4724. The method of claim 4716, wherein heating thesecond portion of the formation comprises heating the second sectionwith a flameless distributed combustor.
 4725. The method of claim 4716,wherein heating the second portion of the formation comprises injectingsteam into at least the portion of the formation.
 4726. The method ofclaim 4716, wherein at least the portion of the aqueous fluid comprisesa liquid phase.
 4727. The method of claim 4716, wherein the aqueousfluid comprises a vapor phase.
 4728. The method of claim 4716, furthercomprising adding carbon dioxide to at least the portion of aqueousfluid to inhibit production of carbon dioxide from carbon within theformation.
 4729. The method of claim 4728, wherein a portion of thecarbon dioxide comprises carbon dioxide removed from the formation.4730. The method of claim 4716, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas.4731. The method of claim 4716, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas,wherein the hydrocarbons are obtained from the produced fluid.
 4732. Themethod of claim 4716, further comprising adding hydrocarbons with carbonnumbers greater than 4 to at least the portion of the aqueous fluid toincrease energy content of the produced synthesis gas.
 4733. The methodof claim 4716, further comprising adding hydrocarbons with carbonnumbers greater than 4 to at least the portion of the aqueous fluid toincrease energy content of the produced synthesis gas, wherein thehydrocarbons are obtained from the produced fluid.
 4734. The method ofclaim 4716, further comprising maintaining a pressure within theformation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4735. Themethod of claim 4716, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4736. The method of claim 4716, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4737. The method of claim 4716, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 4738. The method of claim 4716, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4739. The method of claim 4716, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4740. The method ofclaim 4716, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4741. The method of claim 4716,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4742. The method of claim4716, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, and wherein the unitof heaters comprises a triangular pattern.
 4743. The method of claim4716, further comprising providing heat from three or more heaters to atleast a portion of the formation, wherein three or more of the heatersare located in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4744. A method for in situ production of synthesis gasfrom a hydrocarbon containing formation, comprising: heating a portionof the formation with one or more heaters to create increased andsubstantially uniform permeability within a portion of the formation andto raise a temperature within the portion to a temperature sufficient toallow synthesis gas generation; providing a synthesis gas generatingfluid into the portion through at least one injection wellbore togenerate synthesis gas from hydrocarbons and the synthesis gasgenerating fluid; and producing synthesis gas from at least one wellborein which is positioned a heater of the one or more heaters.
 4745. Themethod of claim 4744, wherein the temperature sufficient to allowsynthesis gas generation is within a range from about 400° C. to about1200° C.
 4746. The method of claim 4744, wherein creating asubstantially uniform permeability comprises heating the portion to atemperature within a range sufficient to pyrolyze hydrocarbons withinthe portion, raising the temperature within the portion at a rate ofless than about 5° C. per day during pyrolyzation and removing a portionof pyrolyzed fluid from the formation.
 4747. The method of claim 4744,further comprising removing fluid from the formation through at leastthe one injection wellbore prior to heating the selected section to thetemperature sufficient to allow synthesis gas generation.
 4748. Themethod of claim 4744, wherein the injection wellbore comprises awellbore of a heater in which is positioned a heater of the one or moreheaters.
 4749. The method of claim 4744, further comprising heating theselected portion during providing the synthesis gas generating fluid toinhibit temperature decrease in at least the portion of the selectedsection due to synthesis gas generation.
 4750. The method of claim 4744,further comprising providing a portion of the heat needed to raise thetemperature sufficient to allow synthesis gas generation by convectingan oxidizing fluid to hydrocarbons within the selected section tooxidize a portion of the hydrocarbons and generate heat.
 4751. Themethod of claim 4744, further comprising controlling the heating of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within the selected section above the temperaturesufficient to generate synthesis gas.
 4752. The method of claim 4744,further comprising: monitoring a composition of the produced synthesisgas; and controlling heating of the selected section and provision ofthe synthesis gas generating fluid to maintain the composition of theproduced synthesis gas within a desired range.
 4753. The method of claim4744, wherein the synthesis gas generating fluid comprises liquid water.4754. The method of claim 4744, wherein the synthesis gas generatingfluid comprises steam.
 4755. The method of claim 4744, wherein thesynthesis gas generating fluid comprises steam to heat the selectedsection and to generate synthesis gas.
 4756. The method of claim 4744,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4757. The method of claim 4756,wherein a portion of the carbon dioxide comprises carbon dioxide removedfrom the formation.
 4758. The method of claim 4744, wherein thesynthesis gas generating fluid comprises carbon dioxide, and wherein aportion of the carbon dioxide reacts with carbon in the formation togenerate carbon monoxide.
 4759. The method of claim 4758, wherein aportion of the carbon dioxide comprises carbon dioxide removed from theformation.
 4760. The method of claim 4744, wherein providing thesynthesis gas generating fluid to the selected section comprises raisinga water table of the formation to allow water to enter the selectedsection.
 4761. The method of claim 4744, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons undergoa reaction within the selected section to increase a H₂ concentrationwithin the produced synthesis gas.
 4762. The method of claim 4744,wherein the synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers greater than 4, and wherein at leasta portion of the hydrocarbons react within the selected section toincrease an energy content of the produced synthesis gas.
 4763. Themethod of claim 4744, further comprising maintaining a pressure withinthe formation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4764. Themethod of claim 4744, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4765. The method of claim 4744, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4766. The method of claim 4744, further comprisingusing a portion of the synthesis gas as a combustion fuel for heatingthe formation.
 4767. The method of claim 4744, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4768. The method of claim 4744, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4769. The method ofclaim 4744, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4770. The method of claim 4744,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4771. The method of claim4744, wherein a temperature of at least the one heater wellbore ismaintained at a temperature of less than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide ofgreater than about
 2. 4772. The method of claim 4744, wherein atemperature of at least the one heater wellbore is maintained at atemperature of greater than approximately 700° C. to produce a synthesisgas having a ratio of H₂ to carbon monoxide of less than about
 2. 4773.The method of claim 4744, wherein a temperature of at least the oneheater wellbore is maintained at a temperature of approximately 700° C.to produce a synthesis gas having a ratio of H₂ to carbon monoxide ofapproximately
 2. 4774. The method of claim 4744, wherein a heater of theone or more heaters comprises an electrical heater.
 4775. The method ofclaim 4744, wherein a heater of the one or more heaters comprises anatural distributed heater.
 4776. The method of claim 4744, wherein aheater of the one or more heaters comprises a flameless distributedcombustor (FDC) heater, and wherein fluids are produced from thewellbore of the FDC heater through a conduit positioned within thewellbore.
 4777. The method of claim 4744, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, and wherein the unit of heaters comprises a triangularpattern.
 4778. The method of claim 4744, further comprising providingheat from three or more heaters to at least a portion of the formation,wherein three or more of the heaters are located in the formation in aunit of heaters, wherein the unit of heaters comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4779. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation such that the heat from the one ormore heaters pyrolyzes at least a portion of the hydrocarbon containingmaterial within the selected section of the formation; producingpyrolysis products from the formation; heating a first portion of aformation with one or more heaters to a temperature sufficient to allowgeneration of synthesis gas; providing a first synthesis gas generatingfluid to the first portion to generate a first synthesis gas; removing aportion of the first synthesis gas from the formation; heating a secondportion of a formation with one or more heaters to a temperaturesufficient to allow generation of synthesis gas having a H₂ to CO ratiogreater than a H₂ to CO ratio of the first synthesis gas; providing asecond synthesis gas generating component to the second portion togenerate a second synthesis gas; removing a portion of the secondsynthesis gas from the formation; and blending a portion of the firstsynthesis gas with a portion of the second synthesis gas to produce ablended synthesis gas having a selected H₂ to CO ratio.
 4780. The methodof claim 4779, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the selected section of theformation.
 4781. The method of claim 4779, wherein the first synthesisgas generating fluid and second synthesis gas generating fluid comprisethe same component.
 4782. The method of claim 4779, further comprisingcontrolling the temperature in the first portion to control acomposition of the first synthesis gas.
 4783. The method of claim 4779,further comprising controlling the temperature in the second portion tocontrol a composition of the second synthesis gas.
 4784. The method ofclaim 4779, wherein the selected ratio is controlled to be approximately2:1 H₂ to CO.
 4785. The method of claim 4779, wherein the selected ratiois controlled to range from approximately 1.8:1 to approximately 2.2:1H₂ to CO.
 4786. The method of claim 4779, wherein the selected ratio iscontrolled to be approximately 3:1 H₂ to CO.
 4787. The method of claim4779, wherein the selected ratio is controlled to range fromapproximately 2.8:1 to approximately 3.2:1 H₂ to CO.
 4788. The method ofclaim 4779, further comprising providing at least a portion of theproduced blended synthesis gas to a condensable hydrocarbon synthesisprocess to produce condensable hydrocarbons.
 4789. The method of claim4788, wherein the condensable hydrocarbon synthesis process comprises aFischer-Tropsch process.
 4790. The method of claim 4789, furthercomprising cracking at least a portion of the condensable hydrocarbonsto form middle distillates.
 4791. The method of claim 4779, furthercomprising providing at least a portion of the produced blendedsynthesis gas to a catalytic methanation process to produce methane.4792. The method of claim 4779, further comprising providing at least aportion of the produced blended synthesis gas to a methanol-synthesisprocess to produce methanol.
 4793. The method of claim 4779, furthercomprising providing at least a portion of the produced blendedsynthesis gas to a gasoline-synthesis process to produce gasoline. 4794.The method of claim 4779, wherein removing a portion of the secondsynthesis gas comprises withdrawing second synthesis gas through aproduction well, wherein a temperature of the production well adjacentto a second syntheses gas production zone is maintained at asubstantially constant temperature configured to produce secondsynthesis gas having the H₂ to CO ratio greater the first synthesis gas.4795. The method of claim 4779, wherein the first synthesis gasproducing fluid comprises CO₂ and wherein the temperature of the firstportion is at a temperature that will result in conversion of CO₂ andcarbon from the first portion to CO to generate a CO rich firstsynthesis gas.
 4796. The method of claim 4779, wherein the secondsynthesis gas producing fluid comprises water and hydrocarbons havingcarbon numbers less than 5, and wherein at least a portion of thehydrocarbons react within the formation to increase a H₂ concentrationwithin the produced second synthesis gas.
 4797. The method of claim4779, wherein blending a portion of the first synthesis gas with aportion of the second synthesis gas comprises producing an intermediatemixture having a H₂ to CO mixture of less than the selected ratio, andsubjecting the intermediate mixture to a shift reaction to reduce anamount of CO and increase an amount of H₂ to produce the selected ratioof H₂ to CO.
 4798. The method of claim 4779, further comprising removingan excess of first synthesis gas from the first portion to have anexcess of CO, subjecting the first synthesis gas to a shift reaction toreduce an amount of CO and increase an amount of H₂ before blending thefirst synthesis gas with the second synthesis gas.
 4799. The method ofclaim 4779, further comprising removing the first synthesis gas from theformation under pressure, and passing removed first synthesis gasthrough a turbine to generate electricity.
 4800. The method of claim4779, further comprising removing the second synthesis gas from theformation under pressure, and passing removed second synthesis gasthrough a turbine to generate electricity.
 4801. The method of claim4779, further comprising generating electricity from the blendedsynthesis gas using a fuel cell.
 4802. The method of claim 4779, furthercomprising generating electricity from the blended synthesis gas using afuel cell, separating carbon dioxide from a fluid exiting the fuel cell,and storing a portion of the separated carbon dioxide within a spentportion of the formation.
 4803. The method of claim 4779, furthercomprising using at least a portion of the blended synthesis gas as acombustion fuel for heating the formation.
 4804. The method of claim4779, further comprising allowing the heat to transfer from the one ormore heaters to the selected section to substantially uniformly increasea permeability of the selected section.
 4805. The method of claim 4779,further comprising controlling heat transfer from the one or moreheaters to produce a permeability within the selected section of greaterthan about 100 millidarcy.
 4806. The method of claim 4779, furthercomprising heating at least the portion of the selected section whenproviding the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4807. The method of claim 4779, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4808. The method of claim 4779, whereinheating the first a portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heaters with heaters disposed inthe wellbores, wherein the heaters are configured to raise temperaturesof the zones to temperatures sufficient to support reaction ofhydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4809. The method of claim 4779, wherein heating the secondportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: heating zones adjacent to wellboresof one or more heaters with heaters disposed in the wellbores, whereinthe heaters are configured to raise temperatures of the zones totemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with an oxidizing fluid; introducing theoxidizing fluid to the zones substantially by diffusion; allowing theoxidizing fluid to react with at least a portion of the hydrocarboncontaining material within the zones to produce heat in the zones; andtransferring heat from the zones to the selected section.
 4810. Themethod of claim 4779, wherein heating the first portion of the selectedsection to a temperature sufficient to allow synthesis gas generationcomprises: introducing an oxidizing fluid into the formation through awellbore; transporting the oxidizing fluid substantially by convectioninto the first portion of the selected section, wherein the firstportion of the selected section is at a temperature sufficient tosupport an oxidation reaction with the oxidizing fluid; and reacting theoxidizing fluid within the first portion of the selected section togenerate heat and raise the temperature of the first portion.
 4811. Themethod of claim 4779, wherein heating the second portion of the selectedsection to a temperature sufficient to allow synthesis gas generationcomprises: introducing an oxidizing fluid into the formation through awellbore; transporting the oxidizing fluid substantially by convectioninto the second portion of the selected section, wherein the secondportion of the selected section is at a temperature sufficient tosupport an oxidation reaction with the oxidizing fluid; and reacting theoxidizing fluid within the second portion of the selected section togenerate heat and raise the temperature of the second portion.
 4812. Themethod of claim 4779, wherein the one or more heaters comprise one ormore electrical heaters disposed in the formation.
 4813. The method ofclaim 4779, wherein the one or more heaters comprises one or morenatural distributed combustors.
 4814. The method of claim 4779, whereinthe one or more heaters comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 4815. The method of claim 4779, wherein heating thefirst portion of the selected section to a temperature sufficient toallow synthesis gas generation and providing a first synthesis gasgenerating fluid to the first portion of the selected section comprisesintroducing steam into the first portion.
 4816. The method of claim4779, wherein heating the second portion of the selected section to atemperature sufficient to allow synthesis gas generation and providing asecond synthesis gas generating fluid to the second portion of theselected section comprises introducing steam into the second portion.4817. The method of claim 4779, further comprising controlling theheating of the first portion of selected section and provision of thefirst synthesis gas generating fluid to maintain a temperature withinthe first portion of the selected section above the temperaturesufficient to generate synthesis gas.
 4818. The method of claim 4779,further comprising controlling the heating of the second portion ofselected section and provision of the second synthesis gas generatingfluid to maintain a temperature within the second portion of theselected section above the temperature sufficient to generate synthesisgas.
 4819. The method of claim 4779, wherein the first synthesis gasgenerating fluid comprises liquid water.
 4820. The method of claim 4779,wherein the second synthesis gas generating fluid comprises liquidwater.
 4821. The method of claim 4779, wherein the first synthesis gasgenerating fluid comprises steam.
 4822. The method of claim 4779,wherein the second synthesis gas generating fluid comprises steam. 4823.The method of claim 4779, wherein the first synthesis gas generatingfluid comprises water and carbon dioxide, wherein the carbon dioxideinhibits production of carbon dioxide from the selected section. 4824.The method of claim 4823, wherein a portion of the carbon dioxide withinthe first synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4825. The method of claim 4779, wherein thesecond synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4826. The method of claim 4825,wherein a portion of the carbon dioxide within the second synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4827. The method of claim 4779, wherein the first synthesis gasgenerating fluid comprises carbon dioxide, and wherein a portion of thecarbon dioxide reacts with carbon in the formation to generate carbonmonoxide.
 4828. The method of claim 4827, wherein a portion of thecarbon dioxide within the first synthesis gas generating fluid comprisescarbon dioxide removed from the formation.
 4829. The method of claim4779, wherein the second synthesis gas generating fluid comprises carbondioxide, and wherein a portion of the carbon dioxide reacts with carbonin the formation to generate carbon monoxide.
 4830. The method of claim4829, wherein a portion of the carbon dioxide within the secondsynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 4831. The method of claim 4779, wherein providing the firstsynthesis gas generating fluid to the first portion of the selectedsection comprises raising a water table of the formation to allow waterto flow into the first portion of the selected section.
 4832. The methodof claim 4779, wherein providing the second synthesis gas generatingfluid to the second portion of the selected section comprises raising awater table of the formation to allow water to flow into the secondportion of the selected section.
 4833. The method of claim 4779, whereinthe first synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within the firstportion of the selected section to increase a H₂ concentration withinthe produced first synthesis gas.
 4834. The method of claim 4779,wherein the second synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within thesecond portion of the selected section to increase a H₂ concentrationwithin the produced second synthesis gas.
 4835. The method of claim4779, wherein the first synthesis gas generating fluid comprises waterand hydrocarbons having carbon numbers greater than 4, and wherein atleast a portion of the hydrocarbons react within the first portion ofthe selected section to increase an energy content of the produced firstsynthesis gas.
 4836. The method of claim 4779, wherein the secondsynthesis gas generating fluid comprises water and hydrocarbons havingcarbon numbers greater than 4, and wherein at least a portion of thehydrocarbons react within at least the second portion of the selectedsection to increase an energy content of the second produced synthesisgas.
 4837. The method of claim 4779, further comprising maintaining apressure within the formation during synthesis gas generation, andpassing produced blended synthesis gas through a turbine to generateelectricity.
 4838. The method of claim 4779, further comprisinggenerating electricity from the blended synthesis gas using a fuel cell.4839. The method of claim 4779, further comprising generatingelectricity from the blended synthesis gas using a fuel cell, separatingcarbon dioxide from a fluid exiting the fuel cell, and storing a portionof the separated carbon dioxide within a spent section of the formation.4840. The method of claim 4779, further comprising using a portion ofthe blended synthesis gas as a combustion fuel for the one or moreheaters.
 4841. The method of claim 4779, further comprising using aportion of the first synthesis gas as a combustion fuel for the one ormore heaters.
 4842. The method of claim 4779, further comprising using aportion of the second synthesis gas as a combustion fuel for the one ormore heaters.
 4843. The method of claim 4779, further comprising using aportion of the blended synthesis gas as a combustion fuel for the one ormore heaters.
 4844. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation suchthat the heat from the one or more heaters pyrolyzes at least some ofthe hydrocarbons within the selected section of the formation; producingpyrolysis products from the formation; heating at least a portion of theselected section to a temperature sufficient to generate synthesis gas;controlling a temperature of at least a portion of the selected sectionto generate synthesis gas having a selected H₂ to CO ratio; providing asynthesis gas generating fluid to at least the portion of the selectedsection to generate synthesis gas; and producing a portion of thesynthesis gas from the formation.
 4845. The method of claim 4844,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation.4846. The method of claim 4844, wherein the selected ratio is controlledto be approximately 2:1 H₂ to CO.
 4847. The method of claim 4844,wherein the selected ratio is controlled to range from approximately1.8:1 to approximately 2.2:1 H₂ to CO.
 4848. The method of claim 4844,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4849. The method of claim 4844, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to approximately 3.2:1 H₂to CO.
 4850. The method of claim 4844, further comprising providing atleast a portion of the produced synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4851.The method of claim 4850, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4852. The method of claim4851, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4853. The method of claim 4844,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4854. The method of claim 4844, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4855. The method of claim 4844, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4856. The method ofclaim 4844, further comprising allowing the heat to transfer from theone or more heaters to the selected section to substantially uniformlyincrease a permeability of the selected section.
 4857. The method ofclaim 4844, further comprising controlling heat transfer from the one ormore heaters to produce a permeability within the selected section ofgreater than about 100 millidarcy.
 4858. The method of claim 4844,further comprising heating at least the portion of the selected sectionwhen providing the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4859. The method of claim 4844, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4860. The method of claim 4844, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heaters with heaters disposed inthe wellbores, wherein the heaters are configured to raise temperaturesof the zones to temperatures sufficient to support reaction ofhydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4861. The method of claim 4844, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: introducing an oxidizing fluid intothe formation through a wellbore; transporting the oxidizing fluidsubstantially by convection into the portion of the selected section,wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4862.The method of claim 4844, wherein the one or more heaters comprise oneor more electrical heaters disposed in the formation.
 4863. The methodof claim 4844, wherein the one or more heaters comprises one or morenatural distributed combustors.
 4864. The method of claim 4844, whereinthe one or more heaters comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 4865. The method of claim 4844, wherein heating atleast the portion of the selected section to a temperature sufficient toallow synthesis gas generation and providing a synthesis gas generatingfluid to at least the portion of the selected section comprisesintroducing steam into the portion.
 4866. The method of claim 4844,further comprising controlling the heating of at least the portion ofselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4867. The method of claim 4844, wherein the synthesis gas generatingfluid comprises liquid water.
 4868. The method of claim 4844, whereinthe synthesis gas generating fluid comprises steam.
 4869. The method ofclaim 4844, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4870. The method of claim4869, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4871. The method of claim 4844, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4872. The method of claim 4871, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4873. The method of claim 4844, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4874. The method of claim 4844, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4875. The method of claim 4844, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4876. The method of claim4844, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4877. The method of claim4844, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4878. The method of claim 4844, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4879. The method of claim 4844, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 4880. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation suchthat the heat from the one or more heaters pyrolyzes at least some ofthe hydrocarbons within the selected section of the formation; producingpyrolysis products from the formation; heating at least a portion of theselected section to a temperature sufficient to generate synthesis gas;controlling a temperature in or proximate to a synthesis gas productionwell to generate synthesis gas having a selected H₂ to CO ratio;providing a synthesis gas generating fluid to at least the portion ofthe selected section to generate synthesis gas; and producing synthesisgas from the formation.
 4881. The method of claim 4880, wherein the oneor more heaters comprise at least two heaters, and wherein superpositionof heat from at least the two heaters pyrolyzes at least somehydrocarbons within the selected section of the formation.
 4882. Themethod of claim 4880, wherein the selected ratio is controlled to beapproximately 2:1 H₂ to CO.
 4883. The method of claim 4880, wherein theselected ratio is controlled to range from approximately 1.8:1 toapproximately 2.2:1 H₂ to CO.
 4884. The method of claim 4880, whereinthe selected ratio is controlled to be approximately 3:1 H₂ to CO. 4885.The method of claim 4880, wherein the selected ratio is controlled torange from approximately 2.8:1 to approximately 3.2:1 H₂ to CO. 4886.The method of claim 4880, further comprising providing at least aportion of the produced synthesis gas to a condensable hydrocarbonsynthesis process to produce condensable hydrocarbons.
 4887. The methodof claim 4886, wherein the condensable hydrocarbon synthesis processcomprises a Fischer-Tropsch process.
 4888. The method of claim 4887,further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4889. The method of claim 4880,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4890. The method of claim 4880, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4891. The method of claim 4880, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4892. The method ofclaim 4880, further comprising allowing the heat to transfer from theone or more heaters to the selected section to substantially uniformlyincrease a permeability of the selected section.
 4893. The method ofclaim 4880, further comprising controlling heat transfer from the one ormore heaters to produce a permeability within the selected section ofgreater than about 100 millidarcy.
 4894. The method of claim 4880,further comprising heating at least the portion of the selected sectionwhen providing the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4895. The method of claim 4880, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4896. The method of claim 4880, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heaters with heaters disposed inthe wellbores, wherein the heaters are configured to raise temperaturesof the zones to temperatures sufficient to support reaction ofhydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4897. The method of claim 4880, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: introducing an oxidizing fluid intothe formation through a wellbore; transporting the oxidizing fluidsubstantially by convection into the portion of the selected section,wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4898.The method of claim 4880, wherein the one or more heaters comprise oneor more electrical heaters disposed in the formation.
 4899. The methodof claim 4880, wherein the one or more heaters comprises one or morenatural distributed combustors.
 4900. The method of claim 4880, whereinthe one or more heaters comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 4901. The method of claim 4880, wherein heating atleast the portion of the selected section to a temperature sufficient toallow synthesis gas generation and providing a synthesis gas generatingfluid to at least the portion of the selected section comprisesintroducing steam into the portion.
 4902. The method of claim 4880,further comprising controlling the heating of at least the portion ofselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4903. The method of claim 4880, wherein the synthesis gas generatingfluid comprises liquid water.
 4904. The method of claim 4880, whereinthe synthesis gas generating fluid comprises steam.
 4905. The method ofclaim 4880, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4906. The method of claim4905, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4907. The method of claim 4880, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4908. The method of claim 4907, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4909. The method of claim 4880, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4910. The method of claim 4880, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4911. The method of claim 4880, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4912. The method of claim4880, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4913. The method of claim4880, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4914. The method of claim 4880, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4915. The method of claim 4880, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 4916. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation suchthat the heat from the one or more heaters pyrolyzes at least some ofthe hydrocarbons within the selected section of the formation; producingpyrolysis products from the formation; heating at least a portion of theselected section to a temperature sufficient to generate synthesis gas;controlling a temperature of at least a portion of the selected sectionto generate synthesis gas having a H₂ to CO ratio different than aselected H₂ to CO ratio; providing a synthesis gas generating fluid toat least the portion of the selected section to generate synthesis gas;and producing synthesis gas from the formation; providing at least aportion of the produced synthesis gas to a shift process wherein anamount of carbon monoxide is converted to carbon dioxide; separating atleast a portion of the carbon dioxide to obtain a gas having a selectedH₂ to CO ratio.
 4917. The method of claim 4916, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 4918. The method of claim4916, wherein the selected ratio is controlled to be approximately 2:1H₂ to CO.
 4919. The method of claim 4916, wherein the selected ratio iscontrolled to range from approximately 1.8:1 to 2.2:1 H₂ to CO. 4920.The method of claim 4916, wherein the selected ratio is controlled to beapproximately 3:1 H₂ to CO.
 4921. The method of claim 4916, wherein theselected ratio is controlled to range from approximately 2.8:1 to 3.2:1H₂ to CO.
 4922. The method of claim 4916, further comprising providingat least a portion of the produced synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4923.The method of claim 4922, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4924. The method of claim4923, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4925. The method of claim 4916,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4926. The method of claim 4916, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4927. The method of claim 4916, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4928. The method ofclaim 4916, further comprising allowing the heat to transfer from theone or more heaters to the selected section to substantially uniformlyincrease a permeability of the selected section.
 4929. The method ofclaim 4916, further comprising controlling heat transfer from the one ormore heaters to produce a permeability within the selected section ofgreater than about 100 millidarcy.
 4930. The method of claim 4916,further comprising heating at least the portion of the selected sectionwhen providing the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4931. The method of claim 4916, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4932. The method of claim 4916, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heaters with heaters disposed inthe wellbores, wherein the heaters are configured to raise temperaturesof the zones to temperatures sufficient to support reaction ofhydrocarbon containing material within the zones with an oxidizingfluid; introducing the oxidizing fluid to the zones substantially bydiffusion; allowing the oxidizing fluid to react with at least a portionof the hydrocarbon containing material within the zones to produce heatin the zones; and transferring heat from the zones to the selectedsection.
 4933. The method of claim 4916, wherein heating at least theportion of the selected section to a temperature sufficient to allowsynthesis gas generation comprises: introducing an oxidizing fluid intothe formation through a wellbore; transporting the oxidizing fluidsubstantially by convection into the portion of the selected section,wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4934.The method of claim 4916, wherein the one or more heaters comprise oneor more electrical heaters disposed in the formation.
 4935. The methodof claim 4916, wherein the one or more heaters comprises one or morenatural distributed combustors.
 4936. The method of claim 4916, whereinthe one or more heaters comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 4937. The method of claim 4916, wherein heating atleast the portion of the selected section to a temperature sufficient toallow synthesis gas generation and providing a synthesis gas generatingfluid to at least the portion of the selected section comprisesintroducing steam into the portion.
 4938. The method of claim 4916,further comprising controlling the heating of at least the portion ofselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4939. The method of claim 4916, wherein the synthesis gas generatingfluid comprises liquid water.
 4940. The method of claim 4916, whereinthe synthesis gas generating fluid comprises steam.
 4941. The method ofclaim 4916, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4942. The method of claim4941, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4943. The method of claim 4916, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4944. The method of claim 4943, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4945. The method of claim 4916, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4946. The method of claim 4916, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4947. The method of claim 4916, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4948. The method of claim4916, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4949. The method of claim4916, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4950. The method of claim 4916, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4951. The method of claim 4916, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 4952. A method of forming a spent portion of formationwithin a hydrocarbon containing formation, comprising: heating a firstportion of the formation to pyrolyze hydrocarbons within the firstportion and to establish a substantially uniform permeability within thefirst portion; and cooling the first portion.
 4953. The method of claim4952, wherein heating the first portion comprises transferring heat tothe first portion from one or more electrical heaters.
 4954. The methodof claim 4952, wherein heating the first portion comprises transferringheat to the first portion from one or more natural distributedcombustors.
 4955. The method of claim 4952, wherein heating the firstportion comprises transferring heat to the first portion from one ormore flameless distributed combustors.
 4956. The method of claim 4952,wherein heating the first portion comprises transferring heat to thefirst portion from heat transfer fluid flowing within one or morewellbores within the formation.
 4957. The method of claim 4956, whereinthe heat transfer fluid comprises steam.
 4958. The method of claim 4956,wherein the heat transfer fluid comprises combustion products from aburner.
 4959. The method of claim 4952, wherein heating the firstportion comprises transferring heat to the first portion from at leasttwo heater wells positioned within the formation, wherein the at leasttwo heater wells are placed in a substantially regular pattern, whereinthe substantially regular pattern comprises repetition of a base heaterunit, and wherein the base heater unit is formed of a number of heaterwells.
 4960. The method of claim 4959, wherein a spacing between a pairof adjacent heater wells is within a range from about 6 m to about 15 m.4961. The method of claim 4959, further comprising removing fluid fromthe formation through one or more production wells.
 4962. The method ofclaim 4961, wherein the one or more production wells are located in apattern, and wherein the one or more production wells are positionedsubstantially at centers of base heater units.
 4963. The method of claim4959, wherein the heater unit comprises three heater wells positionedsubstantially at apexes of an equilateral triangle.
 4964. The method ofclaim 4959, wherein the heater unit comprises four heater wellspositioned substantially at apexes of a rectangle.
 4965. The method ofclaim 4959, wherein the heater unit comprises five heater wellspositioned substantially at apexes of a regular pentagon.
 4966. Themethod of claim 4959, wherein the heater unit comprises six heater wellspositioned substantially at apexes of a regular hexagon.
 4967. Themethod of claim 4952, further comprising introducing water to the firstportion to cool the formation.
 4968. The method of claim 4952, furthercomprising removing steam from the formation.
 4969. The method of claim4968, further comprising using a portion of the removed steam to heat asecond portion of the formation.
 4970. The method of claim 4952, furthercomprising removing pyrolyzation products from the formation.
 4971. Themethod of claim 4952, further comprising generating synthesis gas withinthe portion by introducing a synthesis gas generating fluid into theportion, and removing synthesis gas from the formation.
 4972. The methodof claim 4952, further comprising heating a second section of theformation to pyrolyze hydrocarbons within the second portion, removingpyrolyzation fluid from the second portion, and storing a portion of theremoved pyrolyzation fluid within the first portion.
 4973. The method ofclaim 4972, wherein the portion of the removed pyrolyzation fluid isstored within the first portion when surface facilities that process theremoved pyrolyzation fluid are not able to process the portion of theremoved pyrolyzation fluid.
 4974. The method of claim 4972, furthercomprising heating the first portion to facilitate removal of the storedpyrolyzation fluid from the first portion.
 4975. The method of claim4952, further comprising generating synthesis gas within a secondportion of the formation, removing synthesis gas from the secondportion, and storing a portion of the removed synthesis gas within thefirst portion.
 4976. The method of claim 4975, wherein the portion ofthe removed synthesis gas from the second portion is stored within thefirst portion when surface facilities that process the removed synthesisgas are not able to process the portion of the removed synthesis gas.4977. The method of claim 4975, further comprising heating the firstportion to facilitate removal of the stored synthesis gas from the firstportion.
 4978. The method of claim 4952, further comprising removing atleast a portion of hydrocarbon containing material in the first portionand, further comprising using at least a portion of the hydrocarboncontaining material removed from the formation in a metallurgicalapplication.
 4979. The method of claim 4978, wherein the metallurgicalapplication comprises steel manufacturing.
 4980. A method ofsequestering carbon dioxide within a hydrocarbon containing formation,comprising: heating a portion of the formation to increase permeabilityand form a substantially uniform permeability within the portion;allowing the portion to cool; and storing carbon dioxide within theportion.
 4981. The method of claim 4980, wherein the permeability of theportion is increased to over 100 millidarcy.
 4982. The method of claim4980, further comprising raising a water level within the portion toinhibit migration of the carbon dioxide from the portion.
 4983. Themethod of claim 4980, further comprising heating the portion to releasecarbon dioxide, and removing carbon dioxide from the portion.
 4984. Themethod of claim 4980, further comprising pyrolyzing hydrocarbons withinthe portion during heating of the portion, and removing pyrolyzationproduct from the formation.
 4985. The method of claim 4980, furthercomprising producing synthesis gas from the portion during the heatingof the portion, and removing synthesis gas from the formation.
 4986. Themethod of claim 4980, wherein heating the portion comprises: heatinghydrocarbon containing material adjacent to one or more wellbores to atemperature sufficient to support oxidation of the hydrocarboncontaining material with an oxidizing fluid; introducing the oxidizingfluid to hydrocarbon containing material adjacent to the one or morewellbores to oxidize the hydrocarbons and produce heat; and conveyingproduced heat to the portion.
 4987. The method of claim 4986, whereinheating hydrocarbon containing material adjacent to the one or morewellbores comprises electrically heating the hydrocarbon containingmaterial.
 4988. The method of claim 4986, wherein the temperaturesufficient to support oxidation is in a range from approximately 200° C.to approximately 1200° C.
 4989. The method of claim 4980, whereinheating the portion comprises circulating heat transfer fluid throughone or more heating wells within the formation.
 4990. The method ofclaim 4989, wherein the heat transfer fluid comprises combustionproducts from a burner.
 4991. The method of claim 4989, wherein the heattransfer fluid comprises steam.
 4992. The method of claim 4980, furthercomprising removing fluid from the formation during heating of theformation, and combusting a portion of the removed fluid to generateheat to heat the formation.
 4993. The method of claim 4980, furthercomprising using at least a portion of the carbon dioxide forhydrocarbon bed demethanation prior to storing the carbon dioxide withinthe portion.
 4994. The method of claim 4980, further comprising using aportion of the carbon dioxide for enhanced oil recovery prior to storingthe carbon dioxide within the portion.
 4995. The method of claim 4980,wherein at least a portion of the carbon dioxide comprises carbondioxide generated in a fuel cell.
 4996. The method of claim 4980,wherein at least a portion of the carbon dioxide comprises carbondioxide formed as a combustion product.
 4997. The method of claim 4980,further comprising allowing the portion to cool by introducing water tothe portion; and removing the water from the formation as steam. 4998.The method of claim 4997, further comprising using the steam as a heattransfer fluid to heat a second portion of the formation.
 4999. Themethod of claim 4980, wherein storing carbon dioxide in the portioncomprises adsorbing carbon dioxide to hydrocarbon containing materialwithin the formation.
 5000. The method of claim 4980, wherein storingcarbon dioxide comprises passing a first fluid stream comprising thecarbon dioxide and other fluid through the portion; adsorbing carbondioxide onto hydrocarbon containing material within the formation; andremoving a second fluid stream from the formation, wherein aconcentration of the other fluid in the second fluid stream is greaterthan concentration of other fluid in the first stream due to the absenceof the adsorbed carbon dioxide in the second stream.
 5001. The method ofclaim 4980, wherein an amount of carbon dioxide stored within theportion is equal to or greater than an amount of carbon dioxidegenerated within the portion and removed from the formation duringheating of the portion.
 5002. The method of claim 4980, furthercomprising providing heat from three or more heaters to at least aportion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, and wherein the unit ofheaters comprises a triangular pattern.
 5003. The method of claim 4980,further comprising providing heat from three or more heaters to at leasta portion of the formation, wherein three or more of the heaters arelocated in the formation in a unit of heaters, wherein the unit ofheaters comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 5004. A method of in situ sequestration of carbondioxide within a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a first portion ofthe formation; allowing the heat to transfer from one or more sources toa selected section of the formation such that the heat from the one ormore heaters pyrolyzes at least some of the hydrocarbons within theselected section of the formation; producing pyrolyzation fluids,wherein the pyrolyzation fluids comprise carbon dioxide; and storing anamount of carbon dioxide in the formation, wherein the amount of storedcarbon dioxide is equal to or greater than an amount of carbon dioxidewithin the pyrolyzation fluids.
 5005. The method of claim 5004, whereinthe one or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 5006.The method of claim 5004, wherein the carbon dioxide is stored within aspent portion of the formation.
 5007. The method of claim 5004, whereina portion of the carbon dioxide stored within the formation is carbondioxide separated from the pyrolyzation fluids.
 5008. The method ofclaim 5004, further comprising separating a portion of carbon dioxidefrom the pyrolyzation fluids, and using the carbon dioxide as a floodingagent in enhanced oil recovery.
 5009. The method of claim 5004, furthercomprising separating a portion of carbon dioxide from the pyrolyzationfluids, and using the carbon dioxide as a synthesis gas generating fluidfor the generation of synthesis gas from a section of the formation thatis heated to a temperature sufficient to generate synthesis gas uponintroduction of the synthesis gas generating fluid.
 5010. The method ofclaim 5004, further comprising separating a portion of carbon dioxidefrom the pyrolyzation fluids, and using the carbon dioxide to displacehydrocarbon bed methane.
 5011. The method of claim 5010, wherein thehydrocarbon bed is a deep hydrocarbon bed located over 760 m belowground surface.
 5012. The method of claim 5010, further comprisingadsorbing a portion of the carbon dioxide within the hydrocarbon bed.5013. The method of claim 5004, further comprising using at least aportion of the pyrolyzation fluids as a feed stream for a fuel cell.5014. The method of claim 5013, wherein the fuel cell generates carbondioxide, and further comprising storing an amount of carbon dioxideequal to or greater than an amount of carbon dioxide generated by thefuel cell within the formation.
 5015. The method of claim 5004, whereina spent portion of the formation comprises hydrocarbon containingmaterial within a section of the formation that has been heated and fromwhich condensable hydrocarbons have been produced, and wherein the spentportion of the formation is at a temperature at which carbon dioxideadsorbs onto the hydrocarbon containing material.
 5016. The method ofclaim 5004, further comprising raising a water level within the spentportion to inhibit migration of the carbon dioxide from the portion.5017. The method of claim 5004, wherein producing fluids from theformation comprises removing pyrolyzation products from the formation.5018. The method of claim 5004, wherein producing fluids from theformation comprises heating the selected section to a temperaturesufficient to generate synthesis gas; introducing a synthesis gasgenerating fluid into the selected section; and removing synthesis gasfrom the formation.
 5019. The method of claim 5018, wherein thetemperature sufficient to generate synthesis gas ranges from about 400°C. to about 1200° C.
 5020. The method of claim 5018, wherein heating theselected section comprises introducing an oxidizing fluid into theselected section, reacting the oxidizing fluid within the selectedsection to heat the selected section.
 5021. The method of claim 5018,wherein heating the selected section comprises: heating hydrocarboncontaining material adjacent to one or more wellbores to a temperaturesufficient to support oxidation of the hydrocarbon containing materialwith an oxidant; introducing the oxidant to hydrocarbon containingmaterial adjacent to the one or more wellbores to oxidize thehydrocarbons and produce heat; and conveying produced heat to theportion.
 5022. The method of claim 5004, wherein the spent portion ofthe formation comprises a substantially uniform permeability created byheating the spent formation and removing fluid during formation of thespent portion.
 5023. The method of claim 5004, wherein the one or moreheaters comprise electrical heaters.
 5024. The method of claim 5004,wherein the one or more heaters comprise flameless distributedcombustors.
 5025. The method of claim 5024, wherein a portion of fuelfor the one or more flameless distributed combustors is obtained fromthe formation.
 5026. The method of claim 5004, wherein the one or moreheaters comprise heater wells in the formation through which heattransfer fluid is circulated.
 5027. The method of claim 5026, whereinthe heat transfer fluid comprises combustion products.
 5028. The methodof claim 5026, wherein the heat transfer fluid comprises steam. 5029.The method of claim 5004, wherein condensable hydrocarbons are producedunder pressure, and further comprising generating electricity by passinga portion of the produced fluids through a turbine.
 5030. The method ofclaim 5004, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, and whereinthe unit of heaters comprises a triangular pattern.
 5031. The method ofclaim 5004, further comprising providing heat from three or more heatersto at least a portion of the formation, wherein three or more of theheaters are located in the formation in a unit of heaters, wherein theunit of heaters comprises a triangular pattern, and wherein a pluralityof the units are repeated over an area of the formation to form arepetitive pattern of units.
 5032. A method for in situ production ofenergy from a hydrocarbon containing formation, comprising: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation such that the heat from the one or more heaterspyrolyzes at least a portion of the hydrocarbons within the selectedsection of the formation; producing pyrolysis products from theformation; providing at least a portion of the pyrolysis products to areformer to generate synthesis gas; producing the synthesis gas from thereformer; providing at least a portion of the produced synthesis gas toa fuel cell to produce electricity, wherein the fuel cell produces acarbon dioxide containing exit stream; and storing at least a portion ofthe carbon dioxide in the carbon dioxide containing exit stream in asubsurface formation.
 5033. The method of claim 5032, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from at least the two heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 5034. The method of claim5032, wherein at least a portion of the pyrolysis products are used asfuel in the reformer.
 5035. The method of claim 5032, wherein thesynthesis gas comprises substantially of H₂.
 5036. The method of claim5032, wherein the subsurface formation is a spent portion of theformation.
 5037. The method of claim 5032, wherein the subsurfaceformation is an oil reservoir.
 5038. The method of claim 5037, whereinat least a portion of the carbon dioxide is used as a drive fluid forenhanced oil recovery in the oil reservoir.
 5039. The method of claim5032, wherein the subsurface formation is a coal formation.
 5040. Themethod of claim 5039, wherein at least a portion of the carbon dioxideis used to produce methane from the coal formation.
 5041. The method ofclaim 5039, wherein the coal formation is located over about 760 m belowground surface.
 5042. The method of claim 5040, further comprisingsequestering at least a portion of the carbon dioxide within the coalformation.
 5043. The method of claim 5032, wherein the reformer producesa reformer carbon dioxide containing exit stream.
 5044. The method ofclaim 5032, further comprising storing at least a portion of the carbondioxide in the reformer carbon dioxide containing exit stream in thesubsurface formation.
 5045. The method of claim 5044, wherein thesubsurface formation is a spent portion of the formation.
 5046. Themethod of claim 5044, wherein the subsurface formation is an oilreservoir.
 5047. The method of claim 5046, wherein at least a portion ofthe carbon dioxide in the reformer carbon dioxide containing exit streamis used as a drive fluid for enhanced oil recovery in the oil reservoir.5048. The method of claim 5044, wherein the subsurface formation is acoal formation.
 5049. The method of claim 5048, wherein at least aportion of the carbon dioxide in the reformer carbon dioxide containingexit stream is used to produce methane from the coal formation. 5050.The method of claim 5048, wherein the coal formation is located overabout 760 m below ground surface.
 5051. The method of claim 5049,further comprising sequestering at least a portion of the carbon dioxidein the reformer carbon dioxide containing exit stream within the coalformation.
 5052. The method of claim 5032, wherein the fuel cell is amolten carbonate fuel cell.
 5053. The method of claim 5032, wherein thefuel cell is a solid oxide fuel cell.
 5054. The method of claim 5032,further comprising using a portion of the produced electricity to powerelectrical heaters within the formation.
 5055. The method of claim 5032,further comprising using a portion of the produced pyrolysis products asa feed stream for the fuel cell.
 5056. The method of claim 5032, whereinthe one or more heaters comprise one or more electrical heaters disposedin the formation.
 5057. The method of claim 5032, wherein the one ormore heaters comprise one or more flameless distributed combustorsdisposed in the formation.
 5058. The method of claim 5057, wherein aportion of fuel for the flameless distributed combustors is obtainedfrom the formation.
 5059. The method of claim 5032, wherein the one ormore heaters comprise one or more heater wells, wherein at least oneheater well comprises a conduit disposed within the formation, andfurther comprising heating the conduit by flowing a hot fluid throughthe conduit.
 5060. The method of claim 5032, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheaters.
 5061. A method for producing ammonia using a hydrocarboncontaining formation, comprising: separating air to produce an O₂ richstream and a N₂ rich stream; heating a selected section of the formationto a temperature sufficient to support reaction of hydrocarboncontaining material in the formation to form synthesis gas; providingsynthesis gas generating fluid and at least a portion of the O₂ richstream to the selected section; allowing the synthesis gas generatingfluid and O₂ in the O₂ rich stream to react with at least a portion ofthe hydrocarbon containing material in the formation to generatesynthesis gas; producing synthesis gas from the formation, wherein thesynthesis gas comprises H₂ and CO; providing at least a portion of theH₂ in the synthesis gas to an ammonia synthesis process; providing N₂ tothe ammonia synthesis process; and using the ammonia synthesis processto generate ammonia.
 5062. The method of claim 5061, wherein the ratioof the H₂ to N₂ provided to the ammonia synthesis process isapproximately 3:1.
 5063. The method of claim 5061, wherein the ratio ofthe H₂ to N₂ provided to the ammonia synthesis process ranges fromapproximately 2.8:1 to approximately 3.2:1.
 5064. The method of claim5061, wherein the temperature sufficient to support reaction ofhydrocarbon containing material in the formation to form synthesis gasranges from approximately 400° C. to approximately 1200° C.
 5065. Themethod of claim 5061, further comprising separating at least a portionof carbon dioxide in the synthesis gas from at least a portion of thesynthesis gas.
 5066. The method of claim 5065, wherein the carbondioxide is separated from the synthesis gas by an amine separator. 5067.The method of claim 5066, further comprising providing at least aportion of the carbon dioxide to a urea synthesis process to produceurea.
 5068. The method of claim 5061, wherein at least a portion of theN₂ stream is used to condense hydrocarbons with 4 or more carbon atomsfrom a pyrolyzation fluid.
 5069. The method of claim 5061, wherein atleast a portion of the N₂ rich stream is provided to the ammoniasynthesis process.
 5070. The method of claim 5061, wherein the air isseparated by cryogenic distillation.
 5071. The method of claim 5061,wherein the air is separated by membrane separation.
 5072. The method ofclaim 5061, wherein fluids produced during pyrolysis of a hydrocarboncontaining formation comprise ammonia and, further comprising adding atleast a portion of such ammonia to the ammonia generated from theammonia synthesis process.
 5073. The method of claim 5061, whereinfluids produced during pyrolysis of a hydrocarbon formation arehydrotreated and at least some ammonia is produced during hydrotreating,and, further comprising adding at least a portion of such ammonia to theammonia generated from the ammonia synthesis process.
 5074. The methodof claim 5061, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea.
 5075. The method ofclaim 5061, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea and, furthercomprising providing carbon dioxide from the formation to the ureasynthesis process.
 5076. The method of claim 5061, further comprisingproviding at least a portion of the ammonia to a urea synthesis processto produce urea and, further comprising shifting at least a portion ofthe carbon monoxide to carbon dioxide in a shift process, and furthercomprising providing at least a portion of the carbon dioxide from theshift process to the urea synthesis process.
 5077. The method of claim5061, wherein heating the selected section of the formation to atemperature to support reaction of hydrocarbon containing material inthe formation to form synthesis gas comprises: heating zones adjacent towellbores of one or more heaters with heaters disposed in the wellbores,wherein the heaters are configured to raise temperatures of the zones totemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with O₂ in the O₂ rich stream; introducing theO₂ to the zones substantially by diffusion; allowing O₂ in the O₂ richstream to react with at least a portion of the hydrocarbon containingmaterial within the zones to produce heat in the zones; and transferringheat from the zones to the selected section.
 5078. The method of claim5077, wherein temperatures sufficient to support reaction of hydrocarboncontaining material within the zones with O₂ range from approximately200° C. to approximately 1200° C.
 5079. The method of claim 5077,wherein the one or more heaters comprises one or more electrical heatersdisposed in the formation.
 5080. The method of claim 5077, wherein theone or more heaters comprises one or more natural distributedcombustors.
 5081. The method of claim 5077, wherein the one or moreheaters comprise one or more heater wells, wherein at least one heaterwell comprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 5082. The method of claim 5077, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheaters.
 5083. The method of claim 5061, wherein heating the selectedsection of the formation to a temperature to support reaction ofhydrocarbon containing material in the formation to form synthesis gascomprises: introducing the O₂ rich stream into the formation through awellbore; transporting O₂ in the O₂ rich stream substantially byconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidation reaction with O₂ in the O₂ rich stream; and reacting the O₂within the portion of the selected section to generate heat and raisethe temperature of the portion.
 5084. The method of claim 5083, whereinthe temperature sufficient to support an oxidation reaction with O₂ranges from approximately 200° C. to approximately 1200° C.
 5085. Themethod of claim 5083, wherein the one or more heaters comprises one ormore electrical heaters disposed in the formation.
 5086. The method ofclaim 5083, wherein the one or more heaters comprises one or morenatural distributed combustors.
 5087. The method of claim 5083, whereinthe one or more heaters comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 5088. The method of claim 5083, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heaters.
 5089. The method of claim 5061, further comprisingcontrolling the heating of at least the portion of the selected sectionand provision of the synthesis gas generating fluid to maintain atemperature within at least the portion of the selected section abovethe temperature sufficient to generate synthesis gas.
 5090. The methodof claim 5061, wherein the synthesis gas generating fluid comprisesliquid water.
 5091. The method of claim 5061, wherein the synthesis gasgenerating fluid comprises steam.
 5092. The method of claim 5061,wherein the synthesis gas generating fluid comprises water and carbondioxide wherein the carbon dioxide inhibits production of carbon dioxidefrom the selected section.
 5093. The method of claim 5092, wherein aportion of the carbon dioxide within the synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 5094. The method ofclaim 5061, wherein the synthesis gas generating fluid comprises carbondioxide, and wherein a portion of the carbon dioxide reacts with carbonin the formation to generate carbon monoxide.
 5095. The method of claim5094, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.5096. The method of claim 5061, wherein providing the synthesis gasgenerating fluid to at least the portion of the selected sectioncomprises raising a water table of the formation to allow water to flowinto the at least the portion of the selected section.
 5097. A methodfor producing ammonia using a hydrocarbon containing formation,comprising: generating a first ammonia feed stream from a first portionof the formation; generating a second ammonia feed stream from a secondportion of the formation, wherein the second ammonia feed stream has aH₂ to N₂ ratio greater than a H₂ to N₂ ratio of the first ammonia feedstream; blending at least a portion of the first ammonia feed streamwith at least a portion of the second ammonia feed stream to produce ablended ammonia feed stream having a selected H₂ to N₂ ratio; providingthe blended ammonia feed stream to an ammonia synthesis process; andusing the ammonia synthesis process to generate ammonia.
 5098. Themethod of claim 5097, wherein the selected ratio is approximately 3:1.5099. The method of claim 5097, wherein the selected ratio ranges fromapproximately 2.8:1 to approximately 3.2:1.
 5100. The method of claim5097, further comprising separating at least a portion of carbon dioxidein the first ammonia feed stream from at least a portion of the firstammonia feed stream.
 5101. The method of claim 5100, wherein the carbondioxide is separated from the first ammonia feed stream by an amineseparator.
 5102. The method of claim 5101, further comprising providingat least a portion of the carbon dioxide to a urea synthesis process.5103. The method of claim 5097, further comprising separating at least aportion of carbon dioxide in the blended ammonia feed stream from atleast a portion of the blended ammonia feed stream.
 5104. The method ofclaim 5103, wherein the carbon dioxide is separated from the blendedammonia feed stream by an amine separator.
 5105. The method of claim5104, further comprising providing at least a portion of the carbondioxide to a urea synthesis process.
 5106. The method of claim 5097,further comprising separating at least a portion of carbon dioxide inthe second ammonia feed stream from at least a portion of the secondammonia feed stream.
 5107. The method of claim 5106, wherein the carbondioxide is separated from the second ammonia feed stream by an amineseparator.
 5108. The method of claim 5107, further comprising providingat least a portion of the carbon dioxide to a urea synthesis process.5109. The method of claim 5097, wherein fluids produced during pyrolysisof a hydrocarbon containing formation comprise ammonia and, furthercomprising adding at least a portion of such ammonia to the ammoniagenerated from the ammonia synthesis process.
 5110. The method of claim5097, wherein fluids produced during pyrolysis of a hydrocarbonformation are hydrotreated and at least some ammonia is produced duringhydrotreating, and further comprising adding at least a portion of suchammonia to the ammonia generated from the ammonia synthesis process.5111. The method of claim 5097, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea.5112. The method of claim 5097, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea and,further comprising providing carbon dioxide from the formation to theurea synthesis process.
 5113. The method of claim 5097, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and further comprising shifting atleast a portion of carbon monoxide in the blended ammonia feed stream tocarbon dioxide in a shift process, and further comprising providing atleast a portion of the carbon dioxide from the shift process to the ureasynthesis process.
 5114. A method for producing ammonia using ahydrocarbon containing formation, comprising: heating a selected sectionof the formation to a temperature sufficient to support reaction ofhydrocarbon containing material in the formation to form synthesis gas;providing a synthesis gas generating fluid and an O₂ rich stream to theselected section, wherein the amount of N₂ in the O₂ rich stream issufficient to generate synthesis gas having a selected ratio of H₂ toN₂; allowing the synthesis gas generating fluid and O₂ in the O₂ richstream to react with at least a portion of the hydrocarbon containingmaterial in the formation to generate synthesis gas having a selectedratio of H₂ to N₂; producing the synthesis gas from the formation;providing at least a portion of the H₂ and N₂ in the synthesis gas to anammonia synthesis process; using the ammonia synthesis process togenerate ammonia.
 5115. The method of claim 5114, further comprisingcontrolling a temperature of at least a portion of the selected sectionto generate synthesis gas having the selected H₂ to N₂ ratio.
 5116. Themethod of claim 5114, wherein the selected ratio is approximately 3:1.5117. The method of claim 5114, wherein the selected ratio ranges fromapproximately 2.8:1 to 3.2:1.
 5118. The method of claim 5114, whereinthe temperature sufficient to support reaction of hydrocarbon containingmaterial in the formation to form synthesis gas ranges fromapproximately 400° C. to approximately 1200° C.
 5119. The method ofclaim 5114, wherein the O₂ stream and N₂ stream are obtained bycryogenic separation of air.
 5120. The method of claim 5114, wherein theO₂ stream and N₂ stream are obtained by membrane separation of air.5121. The method of claim 5114, further comprising separating at least aportion of carbon dioxide in the synthesis gas from at least a portionof the synthesis gas.
 5122. The method of claim 5121, wherein the carbondioxide is separated from the synthesis gas by an amine separator. 5123.The method of claim 5122, further comprising providing at least aportion of the carbon dioxide to a urea synthesis process.
 5124. Themethod of claim 5114, wherein fluids produced during pyrolysis of ahydrocarbon containing formation comprise ammonia and, furthercomprising adding at least a portion of such ammonia to the ammoniagenerated from the ammonia synthesis process.
 5125. The method of claim5114, wherein fluids produced during pyrolysis of a hydrocarbonformation are hydrotreated and at least some ammonia is produced duringhydrotreating, and further comprising adding at least a portion of suchammonia to the ammonia generated from the ammonia synthesis process.5126. The method of claim 5114, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea.5127. The method of claim 5114, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea and,further comprising providing carbon dioxide from the formation to theurea synthesis process.
 5128. The method of claim 5114, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and further comprising shifting atleast a portion of carbon monoxide in the synthesis gas to carbondioxide in a shift process, and further comprising providing at least aportion of the carbon dioxide from the shift process to the ureasynthesis process.
 5129. The method of claim 5114, wherein heating aselected section of the formation to a temperature to support reactionof hydrocarbon containing material in the formation to form synthesisgas comprises: heating zones adjacent to wellbores of one or moreheaters with heaters disposed in the wellbores, wherein the heaters areconfigured to raise temperatures of the zones to temperatures sufficientto support reaction of hydrocarbon containing material within the zoneswith O₂ in the O₂ rich stream; introducing the O₂ to the zonessubstantially by diffusion; allowing O₂ in the O₂ rich stream to reactwith at least a portion of the hydrocarbon containing material withinthe zones to produce heat in the zones; and transferring heat from thezones to the selected section.
 5130. The method of claim 5129, whereintemperatures sufficient to support reaction of hydrocarbon containingmaterial within the zones with O₂ range from approximately 200° C. toapproximately 1200° C.
 5131. The method of claim 5129, wherein the oneor more heaters comprises one or more electrical heaters disposed in theformation.
 5132. The method of claim 5129, wherein the one or moreheaters comprises one or more natural distributed combustors.
 5133. Themethod of claim 5129, wherein the one or more heaters comprise one ormore heater wells, wherein at least one heater well comprises a conduitdisposed within the formation, and further comprising heating theconduit by flowing a hot fluid through the conduit.
 5134. The method ofclaim 5129, further comprising using a portion of the synthesis gas as acombustion fuel for the one or more heaters.
 5135. The method of claim5114, wherein heating the selected section of the formation to atemperature to support reaction of hydrocarbon containing material inthe formation to form synthesis gas comprises: introducing the O₂ richstream into the formation through a wellbore; transporting O₂ in the O₂rich stream substantially by convection into the portion of the selectedsection, wherein the portion of the selected section is at a temperaturesufficient to support an oxidation reaction with O₂ in the O₂ richstream; and reacting the O₂ within the portion of the selected sectionto generate heat and raise the temperature of the portion.
 5136. Themethod of claim 5135, wherein the temperature sufficient to support anoxidation reaction with O₂ ranges from approximately 200° C. toapproximately 1200° C.
 5137. The method of claim 5135, wherein the oneor more heaters comprises one or more electrical heaters disposed in theformation.
 5138. The method of claim 5135, wherein the one or moreheaters comprises one or more natural distributed combustors.
 5139. Themethod of claim 5135, wherein the one or more heaters comprise one ormore heater wells, wherein at least one heater well comprises a conduitdisposed within the formation, and further comprising heating theconduit by flowing a hot fluid through the conduit.
 5140. The method ofclaim 5135, further comprising using a portion of the synthesis gas as acombustion fuel for the one or more heaters.
 5141. The method of claim5114, further comprising controlling the heating of at least the portionof the selected section and provision of the synthesis gas generatingfluid to maintain a temperature within at least the portion of theselected section above the temperature sufficient to generate synthesisgas.
 5142. The method of claim 5114, wherein the synthesis gasgenerating fluid comprises liquid water.
 5143. The method of claim 5114,wherein the synthesis gas generating fluid comprises steam.
 5144. Themethod of claim 5114, wherein the synthesis gas generating fluidcomprises water and carbon dioxide, wherein the carbon dioxide inhibitsproduction of carbon dioxide from the selected section.
 5145. The methodof claim 5144, wherein a portion of the carbon dioxide within thesynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 5146. The method of claim 5114, wherein the synthesis gasgenerating fluid comprises carbon dioxide, and wherein a portion of thecarbon dioxide reacts with carbon in the formation to generate carbonmonoxide.
 5147. The method of claim 5146, wherein a portion of thecarbon dioxide within the synthesis gas generating fluid comprisescarbon dioxide removed from the formation.
 5148. The method of claim5114, wherein providing the synthesis gas generating fluid to at leastthe portion of the selected section comprises raising a water table ofthe formation to allow water to flow into the at least the portion ofthe selected section.
 5149. A method for producing ammonia using ahydrocarbon containing formation, comprising: providing a first streamcomprising N₂ and carbon dioxide to the formation; allowing at least aportion of the carbon dioxide in the first stream to adsorb in theformation; producing a second stream from the formation, wherein thesecond stream comprises a lower percentage of carbon dioxide than thefirst stream; providing at least a portion of the N₂ in the secondstream to an ammonia synthesis process.
 5150. The method of claim 5149,wherein the second stream comprises H₂ from the formation.
 5151. Themethod of claim 5149, wherein the first stream is produced from ahydrocarbon containing formation.
 5152. The method of claim 5151,wherein the first stream is generated by reacting a oxidizing fluid withhydrocarbon containing material in the formation.
 5153. The method ofclaim 5149, wherein the second stream comprises H₂ from the formationand, further comprising providing such H₂ to the ammonia synthesisprocess.
 5154. The method of claim 5149, further comprising using theammonia synthesis process to generate ammonia.
 5155. The method of claim5154, wherein fluids produced during pyrolysis of a hydrocarboncontaining formation comprise ammonia and, further comprising adding atleast a portion of such ammonia to the ammonia generated from theammonia synthesis process.
 5156. The method of claim 5154, whereinfluids produced during pyrolysis of a hydrocarbon formation arehydrotreated and at least some ammonia is produced during hydrotreating,and further comprising adding at least a portion of such ammonia to theammonia generated from the ammonia synthesis process.
 5157. The methodof claim 5154, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea.
 5158. The method ofclaim 5154, further comprising providing at least a portion of theammonia to a urea synthesis process to produce urea and, furthercomprising providing carbon dioxide from the formation to the ureasynthesis process.
 5159. The method of claim 5154, further comprisingproviding at least a portion of the ammonia to a urea synthesis processto produce urea and further comprising shifting at least a portion ofcarbon monoxide in the synthesis gas to carbon dioxide in a shiftprocess, and further comprising providing at least a portion of thecarbon dioxide from the shift process to the urea synthesis process.5160. A method of treating a hydrocarbon containing permeable formationin situ, comprising: providing heat from one or more heaters to at leastone portion of the permeable formation; allowing the heat to transferfrom the one or more heaters to a selected mobilization section of thepermeable formation such that the heat from the one or more heaters canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heaters such that an average temperature within atleast a majority of the selected mobilization section of the permeableformation is less than about 150° C.; allowing the heat to transfer fromthe one or more heaters to a selected pyrolyzation section of thepermeable formation such that the heat from the one or more heaters canpyrolyze at least some of the hydrocarbons within the selectedpyrolyzation section of the permeable formation; controlling the heatfrom the one or more heaters such that an average temperature within atleast a majority of the selected pyrolyzation section of the permeableformation is less than about 375° C.; and producing a mixture from thepermeable formation.
 5161. The method of claim 5160, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from the one or more heaters can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation.
 5162. The method of claim 5160, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom the one or more heaters can mobilize at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5163. The method of claim 5160, wherein the one or moreheaters comprise electrical heaters.
 5164. The method of claim 5160,wherein the one or more heaters comprise surface burners.
 5165. Themethod of claim 5160, wherein the one or more heaters comprise flamelessdistributed combustors.
 5166. The method of claim 5160, wherein the oneor more heaters comprise natural distributed combustors.
 5167. Themethod of claim 5160, further comprising disposing the one or moreheaters horizontally within the permeable formation.
 5168. The method ofclaim 5160, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5169. The method of claim 5160,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5170. The method of claim 5160, wherein providing heatfrom the one or more heaters to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heaters, wherein theformation has an average heat capacity(C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 5171. The method of claim 5160,wherein allowing the heat to transfer from the one or more heaters tothe selected mobilization section and/or the selected pyrolyzationsection comprises transferring heat substantially by conduction. 5172.The method of claim 5160, wherein producing the mixture from thepermeable formation further comprises producing mixture having an APIgravity of at least about 25°.
 5173. The method of claim 5160, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 0.5% by weight, of the condensable hydrocarbons, whencalculated on an atomic basis, is nitrogen.
 5174. The method of claim5160, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 7% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is oxygen.
 5175. Themethod of claim 5160, wherein the produced mixture comprises sulfur, andwherein less than about 5% by weight, of the condensable hydrocarbons,when calculated on an atomic basis, is sulfur.
 5176. The method of claim5160, further comprising controlling a pressure within at least amajority of the permeable formation, wherein the controlled pressure isat least about 2 bars absolute.
 5177. The method of claim 5160, furthercomprising altering a pressure within the permeable formation to inhibitproduction of hydrocarbons from the permeable formation having carbonnumbers greater than about
 25. 5178. The method of claim 5160, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 5179. The method of claim 5160, whereinthe produced mixture comprises condensable hydrocarbons and hydrogen,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 5180. The method of claim 5160, wherein producing the mixturefrom the permeable formation further comprises producing the mixture ina production well, wherein the heating is controlled such that themixture can be produced from the permeable formation, and wherein atleast about 4 heaters are disposed in the permeable formation for eachproduction well.
 5181. The method of claim 5160, wherein producing themixture from the permeable formation further comprises producing themixture in a production well, wherein the heating is controlled suchthat the mixture can be produced from the permeable formation, andwherein the production well is disposed substantially horizontallywithin the permeable formation.
 5182. The method of claim 5160, furthercomprising separating the mixture into a gas stream and a liquid stream.5183. The method of claim 5160, further comprising separating themixture into a gas stream and a liquid stream and separating the liquidstream into an aqueous stream and a non-aqueous stream.
 5184. The methodof claim 5160, wherein the mixture is produced from a production well,the method further comprising heating a wellbore of the production wellto inhibit condensation of the mixture within the wellbore.
 5185. Themethod of claim 5160, wherein the mixture is produced from a productionwell, wherein a wellbore of the production well comprises a heaterelement configured to heat the permeable formation adjacent to thewellbore, and further comprising heating the permeable formation withthe heater element to produce the mixture, wherein the mixture comprisesnon-condensable hydrocarbons and H₂.
 5186. The method of claim 5160,wherein a minimum mobilization temperature is about 75° C.
 5187. Themethod of claim 5160, wherein a minimum pyrolysis temperature is about270° C.
 5188. The method of claim 5160, further comprising maintainingthe pressure within the permeable formation above about 2 bars absoluteto inhibit production of fluids having carbon numbers above
 25. 5189.The method of claim 5160, further comprising controlling pressure withinthe permeable formation in a range from about atmospheric pressure toabout 100 bars absolute, as measured at a wellhead of a production well,to control an amount of condensable fluids within the mixture, whereinthe pressure is reduced to increase production of condensable fluids,and wherein the pressure is increased to increase production ofnon-condensable fluids.
 5190. The method of claim 5160, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bars absolute, asmeasured at a wellhead of a production well, to control an API gravityof condensable fluids within the mixture, wherein the pressure isreduced to decrease the API gravity, and wherein the pressure isincreased to reduce the API gravity.
 5191. The method of claim 5160,wherein mobilizing the hydrocarbons within the selected mobilizationsection comprises reducing a viscosity of the hydrocarbons.
 5192. Themethod of claim 5160, further comprising providing a gas to thepermeable formation, wherein the gas is configured to increase a flow ofthe mobilized hydrocarbons from the selected mobilization section of thepermeable formation to the selected pyrolyzation section of thepermeable formation.
 5193. The method of claim 5160, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5194. The method of claim 5160, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5195. The method of claim 5160, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5196. The method of claim5160, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bars absolute.
 5197. The method of claim 5160, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 70 bars absolute.
 5198. A method of treatinga hydrocarbon containing permeable formation in situ, comprising:providing heat from one or more heaters to at least one portion of thepermeable formation; allowing the heat to transfer from the one or moreheaters to a selected mobilization section of the permeable formationsuch that the heat from the one or more heaters can mobilize at leastsome of the hydrocarbons within the selected mobilization section of thepermeable formation; controlling the heat from the one or more heaterssuch that an average temperature within at least a majority of theselected mobilization section of the permeable formation is less thanabout 150° C.; allowing the heat to transfer from the one or moreheaters to a selected pyrolyzation section of the permeable formationsuch that the heat from the one or more heaters can pyrolyze at leastsome of the hydrocarbons within the selected pyrolyzation section of thepermeable formation; controlling the heat from the one or more heaterssuch that an average temperature within at least a majority of theselected pyrolyzation section of the permeable formation is less thanabout 375° C.; allowing at least some of the mobilized hydrocarbons toflow from the selected mobilization section of the permeable formationto the selected pyrolyzation section of the permeable formation; andproducing a mixture from the permeable formation.
 5199. The method ofclaim 5198, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from the one or more heaterscan mobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation.
 5200. The method ofclaim 5198, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from the one or more heaterscan pyrolyze at least some of the hydrocarbons within the selectedpyrolyzation section of the permeable formation.
 5201. The method ofclaim 5198, wherein the one or more heaters comprise electrical heaters.5202. The method of claim 5198, wherein the one or more heaters comprisesurface burners.
 5203. The method of claim 5198, wherein the one or moreheaters comprise flameless distributed combustors.
 5204. The method ofclaim 5198, wherein the one or more heaters comprise natural distributedcombustors.
 5205. The method of claim 5198, further comprising disposingthe one or more heaters horizontally within the permeable formation.5206. The method of claim 5198, further comprising controlling apressure and a temperature within at least a majority of the permeableformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.5207. The method of claim 5198, further comprising controlling the heatsuch that an average heating rate of the selected pyrolyzation sectionis less than about 15° C./day during pyrolysis.
 5208. The method ofclaim 5198, wherein providing heat from the one or more heaters to atleast the portion of permeable formation comprises: heating a selectedvolume (V) of the hydrocarbon containing permeable formation from theone or more heaters, wherein the formation has an average heatcapacity(C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day (Pwr) provided to the selected volume is equal to orless than h*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate (h) of the selected volume is about 10°C./day.
 5209. The method of claim 5198, wherein allowing the heat totransfer from the one or more heaters to the selected mobilizationsection and/or the selected pyrolyzation section comprises transferringheat substantially by conduction.
 5210. The method of claim 5198,wherein producing the mixture from the permeable formation furthercomprises producing a mixture having an API gravity of at least about25°.
 5211. The method of claim 5198, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.5% byweight, of the condensable hydrocarbons, when calculated on an atomicbasis, is nitrogen.
 5212. The method of claim 5198, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about7% by weight, of the condensable hydrocarbons, when calculated on anatomic basis, is oxygen.
 5213. The method of claim 5198, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 5% by weight, of the condensable hydrocarbons, whencalculated on an atomic basis, is sulfur.
 5214. The method of claim5198, further comprising controlling a pressure within at least amajority of the permeable formation, wherein the controlled pressure isat least about 2 bars absolute.
 5215. The method of claim 5198, furthercomprising altering a pressure within the permeable formation to inhibitproduction of hydrocarbons from the permeable formation having carbonnumbers greater than about
 25. 5216. The method of claim 5198, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 5217. The method of claim 5198, whereinthe produced mixture comprises condensable hydrocarbons and hydrogen,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 5218. The method of claim 5198, wherein producing the mixturefrom the permeable formation further comprises producing mixture in aproduction well, wherein the heating is controlled such that the mixturecan be produced from the permeable formation, and wherein at least about4 heaters are disposed in the permeable formation for each productionwell.
 5219. The method of claim 5198, wherein producing the mixture fromthe permeable formation further comprises producing mixture in aproduction well, wherein the heating is controlled such that the mixturecan be produced from the permeable formation, and wherein the productionwell is disposed substantially horizontally within the permeableformation.
 5220. The method of claim 5198, further comprising separatingthe mixture into a gas stream and a liquid stream.
 5221. The method ofclaim 5198, further comprising separating the mixture into a gas streamand a liquid stream and separating the liquid stream into an aqueousstream and a non-aqueous stream.
 5222. The method of claim 5198, whereinthe mixture is produced from a production well, the method furthercomprising heating a wellbore of the production well to inhibitcondensation of the mixture within the wellbore.
 5223. The method ofclaim 5198, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the permeable formation adjacent to the wellbore, andfurther comprising heating the permeable formation with the heaterelement to produce the mixture, wherein the mixture comprisesnon-condensable hydrocarbons and H₂.
 5224. The method of claim 5198,wherein a minimum mobilization temperature is about 75° C.
 5225. Themethod of claim 5198, wherein a minimum pyrolysis temperature is about270° C.
 5226. The method of claim 5198, further comprising maintainingthe pressure within the permeable formation above about 2 bars absoluteto inhibit production of fluids having carbon numbers above
 25. 5227.The method of claim 5198, further comprising controlling pressure withinthe permeable formation in a range from about atmospheric pressure toabout 100 bars absolute, as measured at a wellhead of a production well,to control an amount of condensable fluids within the mixture, whereinthe pressure is reduced to increase production of condensable fluids,and wherein the pressure is increased to increase production ofnon-condensable fluids.
 5228. The method of claim 5198, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bars absolute, asmeasured at a wellhead of a production well, to control an API gravityof condensable fluids within the mixture, wherein the pressure isreduced to decrease the API gravity, and wherein the pressure isincreased to reduce the API gravity.
 5229. The method of claim 5198,wherein mobilizing the hydrocarbons within the selected mobilizationsection comprises reducing a viscosity of the hydrocarbons.
 5230. Themethod of claim 5198, further comprising providing a gas to thepermeable formation, wherein the gas is configured to increase a flow ofthe mobilized hydrocarbons from the selected mobilization section of thepermeable formation to the selected pyrolyzation section of thepermeable formation.
 5231. The method of claim 5198, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5232. The method of claim 5198, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5233. The method of claim 5198, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5234. The method of claim5198, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bars absolute.
 5235. The method of claim 5198, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 100 bars absolute.
 5236. A method oftreating a hydrocarbon containing permeable formation in situ,comprising: providing heat from one or more heaters to at least oneportion of the permeable formation; allowing the heat to transfer fromthe one or more heaters to a selected mobilization section of thepermeable formation such that the heat from the one or more heaters canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heaters such that an average temperature within atleast a majority of the selected mobilization section of the permeableformation is less than about 150° C.; allowing the heat to transferfront the one or more heaters to a selected pyrolyzation section of thepermeable formation such that the heat from the one or more heaters canpyrolyze at least some of the hydrocarbons within the selectedpyrolyzation section of the permeable formation; controlling the heatfrom the one or more heaters such that an average temperature within atleast a majority of the selected pyrolyzation section of the permeableformation is less than about 375° C.; allowing at least some of themobilized hydrocarbons to flow from the selected mobilization section ofthe permeable formation to the selected pyrolyzation section of thepermeable formation; providing a gas to the permeable formation, whereinthe gas is configured to increase a flow of the mobilized hydrocarbonsfrom the selected mobilization section of the permeable formation to theselected pyrolyzation section of the permeable formation; and producinga mixture from the permeable formation.
 5237. The method of claim 5236,wherein the one or more heaters comprise at least two heaters, andwherein the heat from the one or more heaters can mobilize at least someof the hydrocarbons within the selected mobilization section of thepermeable formation.
 5238. The method of claim 5236, wherein the one ormore heaters comprise at least two heaters, and wherein the heat fromthe one or more heaters can pyrolyze at least some of the hydrocarbonswithin the selected pyrolyzation section of the permeable formation.5239. The method of claim 5236, wherein the one or more heaters compriseelectrical heaters.
 5240. The method of claim 5236, wherein the one ormore heaters comprise surface burners.
 5241. The method of claim 5236,wherein the one or more heaters comprise flameless distributedcombustors.
 5242. The method of claim 5236, wherein the one or moreheaters comprise natural distributed combustors.
 5243. The method ofclaim 5236, further comprising disposing the one or more heatershorizontally within the permeable formation.
 5244. The method of claim5236, further comprising controlling a pressure and a temperature withinat least a majority of the permeable formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 5245. The method of claim 5236,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5246. The method of claim 5236, wherein providing heatfrom the one or more heaters to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heaters, wherein theformation has an average heat capacity(C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 5247. The method of claim 5236,wherein allowing the heat to transfer from the one or more heaters tothe selected mobilization section and/or the selected pyrolyzationsection comprises transferring heat substantially by conduction. 5248.The method of claim 5236, wherein producing mixture from the permeableformation further comprises producing mixture having an API gravity ofat least about 25°.
 5249. The method of claim 5236, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about0.5% by weight, of the condensable hydrocarbons, when calculated on anatomic basis, is nitrogen.
 5250. The method of claim 5236, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 7% by weight, of the condensable hydrocarbons, whencalculated on an atomic basis, is oxygen.
 5251. The method of claim5236, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 5% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is sulfur.
 5252. Themethod of claim 5236, further comprising controlling a pressure withinat least a majority of the permeable formation, wherein the controlledpressure is at least about 2 bars absolute.
 5253. The method of claim5236, further comprising altering a pressure within the permeableformation to inhibit production of hydrocarbons from the permeableformation having carbon numbers greater than about
 25. 5254. The methodof claim 5236, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 5255. The method ofclaim 5236, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5256. The method of claim 5236, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heaters are disposed in thepermeable formation for each production well.
 5257. The method of claim5236, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5258. Themethod of claim 5236, further comprising separating the mixture into agas stream and a liquid stream.
 5259. The method of claim 5236, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5260. The method of claim 5236, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5261. The method of claim 5236, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprise non-condensable hydrocarbons andH₂.
 5262. The method of claim 5236, wherein a minimum mobilizationtemperature is about 75° C.
 5263. The method of claim 5236, wherein aminimum pyrolysis temperature is about 270° C.
 5264. The method of claim5236, further comprising maintaining the pressure within the permeableformation above about 2 bars absolute to inhibit production of fluidshaving carbon numbers above
 25. 5265. The method of claim 5236, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bars absolute, asmeasured at a wellhead of a production well, to control an amount ofcondensable fluids within the mixture, wherein the pressure is reducedto increase production of condensable fluids, and wherein the pressureis increased to increase production of non-condensable fluids.
 5266. Themethod of claim 5236, further comprising controlling pressure within thepermeable formation in a range from about atmospheric pressure to about100 bars absolute, as measured at a wellhead of a production well, tocontrol an API gravity of condensable fluids within the mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5267. The method ofclaim 5236, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5268. The method of claim 5236, wherein the provided gas comprisescarbon dioxide.
 5269. The method of claim 5236, wherein the provided gascomprises nitrogen.
 5270. The method of claim 5236, further comprisingcontrolling a pressure of the provided gas such that the flow of themobilized hydrocarbons is controlled.
 5271. The method of claim 5236,further comprising controlling a pressure of the provided gas such thatthe flow of the mobilized hydrocarbons is controlled, wherein thepressure of the provided gas is above about 2 bars absolute.
 5272. Themethod of claim 5236, further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is below about 100bars absolute.
 5273. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheaters to at least one portion of the permeable formation; allowing theheat to transfer from the one or more heaters to a selected mobilizationsection of the permeable formation such that the heat from the one ormore heaters can mobilize at least some of the hydrocarbons within theselected mobilization section of the permeable formation; controllingthe heat from the one or more heaters such that an average temperaturewithin at least a majority of the selected mobilization section of thepermeable formation is less than about 150° C.; allowing the heat totransfer from the one or more heaters to a selected pyrolyzation sectionof the permeable formation such that the heat from the one or moreheaters can pyrolyze at least some of the hydrocarbons within theselected pyrolyzation section of the permeable formation; controllingthe heat from the one or more heaters such that an average temperaturewithin at least a majority of the selected pyrolyzation section of thepermeable formation is less than about 375° C.; allowing at least someof the mobilized hydrocarbons to flow from the selected mobilizationsection of the permeable formation to the selected pyrolyzation sectionof the permeable formation; providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation; controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled; and producing a mixturefrom the permeable formation.
 5274. The method of claim 5273, whereinthe one or more heaters comprise at least two heaters, and whereinsuperposition of heat from the one or more heaters can mobilize at leastsome of the hydrocarbons within the selected mobilization section of thepermeable formation.
 5275. The method of claim 5273, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from the one or more heaters can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5276. The method of claim 5273, wherein the one or moreheaters comprise electrical heaters.
 5277. The method of claim 5273,wherein the one or more heaters comprise surface burners.
 5278. Themethod of claim 5273, wherein the one or more heaters comprise flamelessdistributed combustors.
 5279. The method of claim 5273, wherein the oneor more heaters comprise natural distributed combustors.
 5280. Themethod of claim 5273, further comprising disposing the one or moreheaters horizontally within the permeable formation.
 5281. The method ofclaim 5273, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5282. The method of claim 5273,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5283. The method of claim 5273, wherein providing heatfrom the one or more heaters to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heaters, wherein theformation has an average heat capacity(C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 5284. The method of claim 5273,wherein allowing the heat to transfer from the one or more heaters tothe selected mobilization section and/or the selected pyrolyzationsection comprises transferring heat substantially by conduction. 5285.The method of claim 5273, wherein producing the mixture from thepermeable formation further comprises producing mixture having an APIgravity of at least about 25°.
 5286. The method of claim 5273, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 0.5% by weight, of the condensable hydrocarbons, whencalculated on an atomic basis, is nitrogen.
 5287. The method of claim5273, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 7% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is oxygen.
 5288. Themethod of claim 5273, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight, of thecondensable hydrocarbons, when calculated on an atomic basis, is sulfur.5289. The method of claim 5273, further comprising controlling apressure within at least a majority of the permeable formation, whereinthe controlled pressure is at least about 2 bars absolute.
 5290. Themethod of claim 5273, further comprising altering a pressure within thepermeable formation to inhibit production of hydrocarbons from thepermeable formation having carbon numbers greater than about
 25. 5291.The method of claim 5273, further comprising: providing hydrogen (H₂) tothe heated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 5292. Themethod of claim 5273, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5293. The method of claim 5273, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heaters are disposed in thepermeable formation for each production well.
 5294. The method of claim5273, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5295. Themethod of claim 5273, further comprising separating the mixture into agas stream and a liquid stream.
 5296. The method of claim 5273, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5297. The method of claim 5273, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5298. The method of claim 5273, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprises non-condensable hydrocarbons andH₂.
 5299. The method of claim 5273, wherein a minimum mobilizationtemperature is about 75° C.
 5300. The method of claim 5273, wherein aminimum pyrolysis temperature is about 270° C.
 5301. The method of claim5273, further comprising maintaining the pressure within the permeableformation above about 2 bars absolute to inhibit production of fluidshaving carbon numbers above
 25. 5302. The method of claim 5273, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bars absolute, asmeasured at a wellhead of a production well, to control an amount ofcondensable fluids within the mixture, wherein the pressure is reducedto increase production of condensable fluids, and wherein the pressureis increased to increase production of non-condensable fluids.
 5303. Themethod of claim 5273, further comprising controlling pressure within thepermeable formation in a range from about atmospheric pressure to about100 bars absolute, as measured at a wellhead of a production well, tocontrol an API gravity of condensable fluids within the mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5304. The method ofclaim 5273, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5305. The method of claim 5273, wherein the provided gas comprisescarbon dioxide.
 5306. The method of claim 5273, wherein the provided gascomprises nitrogen.
 5307. The method of claim 5273, wherein the pressureof the provided gas is above about 2 bars absolute.
 5308. The method ofclaim 5273, wherein the pressure of the provided gas is below about 70bars absolute.
 5309. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheaters to at least one portion of the permeable formation; allowing theheat to transfer from the one or more heaters to a selected mobilizationsection of the permeable formation such that the heat from the one ormore heaters can mobilize at least some of the hydrocarbons within theselected mobilization section of the permeable formation; controllingthe heat from the one or more heaters such that an average temperaturewithin at least a majority of the selected mobilization section of thepermeable formation is less than about 150° C.; allowing the heat totransfer from the one or more heaters to a selected pyrolyzation sectionof the permeable formation such that the heat from the one or moreheaters can pyrolyze at least some of the hydrocarbons within theselected pyrolyzation section of the permeable formation; controllingthe heat from the one or more heaters such that an average temperaturewithin at least a majority of the selected pyrolyzation section of thepermeable formation is less than about 375° C.; and producing a mixturefrom the permeable formation in a production well, wherein theproduction well is disposed substantially horizontally within thepermeable formation.
 5310. The method of claim 5309, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from the one or more heaters can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation.
 5311. The method of claim 5309, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom the one or more heaters can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5312. The method of claim 5309, wherein the one or moreheaters comprise electrical heaters.
 5313. The method of claim 5309,wherein the one or more heaters comprise surface burners.
 5314. Themethod of claim 5309, wherein the one or more heaters comprise flamelessdistributed combustors.
 5315. The method of claim 5309, wherein the oneor more heaters comprise natural distributed combustors.
 5316. Themethod of claim 5309, further comprising disposing the one or moreheaters horizontally within the permeable formation.
 5317. The method ofclaim 5309, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5318. The method of claim 5309,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5319. The method of claim 5309, wherein providing heatfrom the one or more heaters to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heaters, wherein theformation has an average heat capacity(C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day (Pwr) provided to the selectedvolume is equal to or less than h*V*C_(v)*ρ_(B), wherein ρ_(B) isformation bulk density, and wherein an average heating rate (h) of theselected volume is about 10° C./day.
 5320. The method of claim 5309,wherein allowing the heat to transfer from the one or more heaters tothe selected mobilization section and/or the selected pyrolyzationsection comprises transferring heat substantially by conduction. 5321.The method of claim 5309, wherein producing mixture from the permeableformation further comprises producing mixture having an API gravity ofat least about 25°.
 5322. The method of claim 5309, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about0.5% by weight, of the condensable hydrocarbons, when calculated on anatomic basis, is nitrogen.
 5323. The method of claim 5309, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 7% by weight, of the condensable hydrocarbons, whencalculated on an atomic basis, is oxygen.
 5324. The method of claim5309, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 5% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is sulfur.
 5325. Themethod of claim 5309, further comprising controlling a pressure withinat least a majority of the permeable formation, wherein the controlledpressure is at least about 2 bars absolute.
 5326. The method of claim5309, further comprising altering a pressure within the permeableformation to inhibit production of hydrocarbons from the permeableformation having carbon numbers greater than about
 25. 5327. The methodof claim 5309, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 5328. The method ofclaim 5309, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5329. The method of claim 5309, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heaters are disposed in thepermeable formation for each production well.
 5330. The method of claim5309, further comprising separating the mixture into a gas stream and aliquid stream.
 5331. The method of claim 5309, further comprisingseparating the mixture into a gas stream and a liquid stream andseparating the liquid stream into an aqueous stream and a non-aqueousstream.
 5332. The method of claim 5309, wherein the mixture is producedfrom a production well, the method further comprising heating a wellboreof the production well to inhibit condensation of the mixture within thewellbore.
 5333. The method of claim 5309, wherein the mixture isproduced from a production well, wherein a wellbore of the productionwell comprises a heater element configured to heat the permeableformation adjacent to the wellbore, and further comprising heating thepermeable formation with the heater element to produce the mixture,wherein the mixture comprises non-condensable hydrocarbons and H₂. 5334.The method of claim 5309, wherein a minimum mobilization temperature isabout 75° C.
 5335. The method of claim 5309, wherein a minimum pyrolysistemperature is about 270° C.
 5336. The method of claim 5309, furthercomprising maintaining the pressure within the permeable formation aboveabout 2 bars absolute to inhibit production of fluids having carbonnumbers above
 25. 5337. The method of claim 5309, further comprisingcontrolling pressure within the permeable formation in a range fromabout atmospheric pressure to about 100 bars absolute, as measured at awellhead of a production well, to control an amount of condensablefluids within the mixture, wherein the pressure is reduced to increaseproduction of condensable fluids, and wherein the pressure is increasedto increase production of non-condensable fluids.
 5338. The method ofclaim 5309, further comprising controlling pressure within the permeableformation in a range from about atmospheric pressure to about 100 barsabsolute, as measured at a wellhead of a production well, to control anAPI gravity of condensable fluids within the mixture, wherein thepressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5339. The method ofclaim 5309, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5340. The method of claim 5309, further comprising providing a gas tothe permeable formation, wherein the gas is configured to increase aflow of the mobilized hydrocarbons from the selected mobilizationsection of the permeable formation to the selected pyrolyzation sectionof the permeable formation.
 5341. The method of claim 5309, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5342. The method of claim 5309, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5343. The method of claim 5309, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5344. The method of claim5309, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bars absolute.
 5345. The method of claim 5309, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 70 bars absolute.
 5346. A method of treatinga hydrocarbon containing permeable formation in situ, comprising:providing heat from one or more heaters to at least one portion of thepermeable formation; allowing the heat to transfer from the one or moreheaters to a selected mobilization section of the permeable formationsuch that the heat from the one or more heaters can mobilize at leastsome of the hydrocarbons within the selected mobilization section of thepermeable formation; controlling the heat from the one or more heaterssuch that an average temperature within at least a majority of theselected mobilization section of the permeable formation is less thanabout 150° C.; providing a gas to the permeable formation, wherein thegas is configured to increase a flow of the mobilized hydrocarbonswithin the permeable formation; and producing a mixture from thepermeable formation.
 5347. The method of claim 5346, wherein the one ormore heaters comprise at least two heaters, and wherein superposition ofheat from the one or more heaters can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation.
 5348. The method of claim 5346, wherein the one or moreheaters comprise electrical heaters.
 5349. The method of claim 5346,wherein the one or more heaters comprise surface burners.
 5350. Themethod of claim 5346, wherein the one or more heaters comprise flamelessdistributed combustors.
 5351. The method of claim 5346, wherein the oneor more heaters comprise natural distributed combustors.
 5352. Themethod of claim 5346, further comprising disposing the one or moreheaters horizontally within the permeable formation.
 5353. The method ofclaim 5346, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5354. The method of claim 5346,wherein providing heat from the one or more heaters to at least theportion of permeable formation comprises: heating a selected volume (V)of the hydrocarbon containing permeable formation from the one or moreheaters, wherein the formation has an average heat capacity(C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/day (Pwr)provided to the selected volume is equal to or less thanh*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, and wherein anaverage heating rate (h) of the selected volume is about 10° C./day.5355. The method of claim 5346, wherein allowing the heat to transferfrom the one or more heaters to the selected mobilization sectioncomprises transferring heat substantially by conduction.
 5356. Themethod of claim 5346, further comprising controlling a pressure withinat least a majority of the permeable formation, wherein the controlledpressure is at least about 2 bars absolute.
 5357. The method of claim5346, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein at least about 4 heaters are disposedin the permeable formation for each production well.
 5358. The method ofclaim 5346, wherein producing the mixture from the permeable formationfurther comprises producing the mixture in a production well, whereinthe heating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5359. Themethod of claim 5346, further comprising separating the mixture into agas stream and a liquid stream.
 5360. The method of claim 5346, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5361. The method of claim 5346, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5362. The method of claim 5346, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprise non-condensable hydrocarbons andH₂.
 5363. The method of claim 5346, wherein a minimum mobilizationtemperature is about 75° C.
 5364. The method of claim 5346, whereinmobilizing the hydrocarbons within the selected mobilization sectioncomprises reducing a viscosity of the hydrocarbons.
 5365. The method ofclaim 5346, wherein the provided gas comprises carbon dioxide.
 5366. Themethod of claim 5346, wherein the provided gas comprises nitrogen. 5367.The method of claim 5346, further comprising controlling a pressure ofthe provided gas such that the flow of the mobilized hydrocarbons iscontrolled.
 5368. The method of claim 5346, further comprisingcontrolling a pressure of the provided gas such that the flow of themobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is above about 2 bars absolute.
 5369. The method of claim5346, further comprising controlling a pressure of the provided gas suchthat the flow of the mobilized hydrocarbons is controlled, wherein thepressure of the provided gas is below about 70 bars absolute.
 5370. Amethod of treating a hydrocarbon containing permeable formation in situ,comprising: providing heat from one or more heaters to at least oneportion of the permeable formation; allowing the heat to transfer fromthe one or more heaters to a selected mobilization section of thepermeable formation such that the heat from the one or more heaters canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heaters such that an average temperature within atleast a majority of the selected mobilization section of the permeableformation is less than about 150° C.; providing a gas to the permeableformation, wherein the gas is configured to increase a flow of themobilized hydrocarbons within the permeable formation; controlling apressure of the provided gas such that the flow of the mobilizedhydrocarbons is controlled; and producing a mixture from the permeableformation.
 5371. The method of claim 5370, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom the one or more heaters can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation.
 5372. The method of claim 5370, wherein the one or moreheaters comprise electrical heaters.
 5373. The method of claim 5370,wherein the one or more heaters comprise surface burners. 5374 Themethod of claim 5370, wherein the one or more heaters comprise flamelessdistributed combustors.
 5375. The method of claim 5370, wherein the oneor more heaters comprise natural distributed combustors.
 5376. Themethod of claim 5370, further comprising disposing the one or moreheaters horizontally within the permeable formation.
 5377. The method ofclaim 5370, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5378. The method of claim 5370,wherein providing heat from the one or more heaters to at least theportion of permeable formation comprises: heating a selected volume (V)of the hydrocarbon containing permeable formation from the one or moreheaters, wherein the formation has an average heat capacity(C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/day (Pwr)provided to the selected volume is equal to or less thanh*V*C_(v)*ρ_(B), wherein ρ_(B) is formation bulk density, and wherein anaverage heating rate (h) of the selected volume is about 10° C./day.5379. The method of claim 5370, wherein allowing the heat to transferfrom the one or more heaters to the selected mobilization sectioncomprises transferring heat substantially by conduction.
 5380. Themethod of claim 5370, further comprising controlling a pressure withinat least a majority of the permeable formation, wherein the controlledpressure is at least about 2 bars absolute.
 5381. The method of claim5370, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein at least about 4 heaters are disposedin the permeable formation for each production well.
 5382. The method ofclaim 5370, wherein producing the mixture from the permeable formationfurther comprises producing the mixture in a production well, whereinthe heating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5383. Themethod of claim 5370, further comprising separating the mixture into agas stream and a liquid stream.
 5384. The method of claim 5370, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5385. The method of claim 5370, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5386. The method of claim 5370, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprise non-condensable hydrocarbons andH₂.
 5387. The method of claim 5370, wherein a minimum mobilizationtemperature is about 75° C.
 5388. The method of claim 5370, whereinmobilizing the hydrocarbons within the selected mobilization sectioncomprises reducing a viscosity of the hydrocarbons.
 5389. The method ofclaim 5370, wherein the provided gas comprises carbon dioxide.
 5390. Themethod of claim 5370, wherein the provided gas comprises nitrogen. 5391.The method of claim 5370, wherein the pressure of the provided gas isabove about 2 bars absolute.
 5392. The method of claim 5370, wherein thepressure of the provided gas is below about 70 bars absolute.
 5393. Amethod for treating hydrocarbons in at least a portion of a hydrocarboncontaining formation, wherein the portion has an average permeability ofless than about 10 millidarcy, comprising: providing heat from one ormore heaters to the formation; allowing the heat to transfer from one ormore of the heaters to a selected section of the formation such thatheat from the heaters pyrolyzes at least some hydrocarbons within theselected section, and wherein heat from the heaters increases thepermeability of at least a portion of the selected section; andproducing a mixture comprising hydrocarbons from the formation. 5394.The method of claim 5393, wherein the one or more heaters comprise atleast two heaters, and wherein superposition of heat from at least thetwo heaters pyrolyzes at least some hydrocarbons within the selectedsection of the formation, and wherein superposition of heat from atleast the two heaters increases the permeability of at least the portionof the selected section.
 5395. The method of claim 5393, furthercomprising allowing heat to transfer from at least one of the heaters tothe selected section to create thermal fractures in the formationwherein the thermal fractures substantially increase the permeability ofthe selected section.
 5396. The method of claim 5393, wherein the heatis provided such that an average temperature in the selected sectionranges from approximately about 270° C. to about 375° C.
 5397. Themethod of claim 5393, wherein at least one of the heaters comprises anelectrical heater located in the formation.
 5398. The method of claim5393, wherein at least one of the heaters is located in a heater well,and wherein at least one of the heater wells comprises a conduit locatedin the formation, and further comprising heating the conduit by flowinga hot fluid through the conduit.
 5399. The method of claim 5393, whereinat least some of the heaters are arranged in a triangular pattern. 5400.The method of claim 5393, further comprising: monitoring a compositionof the produced mixture; and controlling a pressure in at least aportion of the formation to control the composition of the producedmixture.
 5401. The method of claim 5400, wherein the pressure iscontrolled by a valve proximate to a location where the mixture isproduced.
 5402. The method of claim 5400, wherein the pressure iscontrolled such that pressure proximate to one or more of the heaters isgreater than a pressure proximate to a location where the fluid isproduced.
 5403. The method of claim 5393, wherein an average distancebetween heaters is between about 2 m and about 8 m.
 5404. A method fortreating hydrocarbons in at least a portion of a hydrocarbon containingformation, wherein the portion has an average permeability of less thanabout 10 millidarcy, comprising: providing heat from one or more heatersto the formation; allowing the heat to transfer from one or more of theheaters to a selected section of the formation such that heat from theheaters pyrolyzes at least some hydrocarbons within the selectedsection, and wherein heat from the heaters vaporizes at least a portionof the hydrocarbons in the selected section; and producing a mixturecomprising hydrocarbons from the formation.
 5405. The method of claim5404, wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons within the selected section of the formation,and wherein superposition of heat from at least the two heatersvaporizes at least the portion of the hydrocarbons in the selectedsection.
 5406. The method of claim 5404, further comprising allowingheat to transfer from at least one of the heaters to the selectedsection to create thermal fractures in the formation, wherein thethermal fractures substantially increase the permeability of theselected section.
 5407. The method of claim 5404, wherein the heat isprovided such that an average temperature in the selected section rangesfrom approximately about 270° C. to about 375° C.
 5408. The method ofclaim 5404, wherein at least one of the heaters comprises an electricalheater located in the formation.
 5409. The method of claim 5404, whereinat least one of the heaters is located in a heater well, and wherein atleast one of the heater wells comprises a conduit located in theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5410. The method of claim 5404, wherein atleast some of the heaters are arranged in a triangular pattern. 5411.The method of claim 5404, further comprising: monitoring a compositionof the produced mixture; and controlling a pressure in at least aportion of the formation to control the composition of the producedmixture.
 5412. The method of claim 5411, wherein the pressure iscontrolled by a valve proximate to a location where the mixture isproduced.
 5413. The method of claim 5411, wherein the pressure iscontrolled such that pressure proximate to one or more of the heaters isgreater than a pressure proximate to a location where the mixture isproduced.
 5414. The method of claim 5404, wherein an average distancebetween heaters is between about 2 m and about 8 m.
 5415. A method fortreating hydrocarbons in at least a portion of a hydrocarbon containingformation, wherein the portion has an average permeability of less thanabout 10 millidarcy, comprising: providing heat from one or more heatersto the formation, wherein at least one of the heaters is located in aheater well; allowing the heat to transfer from one or more of theheaters to a selected section of the formation such that heat from theheaters pyrolyzes at least some hydrocarbons within the selectedsection, and wherein heat from the heaters pressurizes at least aportion of the selected section; and producing a mixture comprisinghydrocarbons from the formation, wherein the mixture is produced fromone or more heater wells.
 5416. The method of claim 5415, wherein theone or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 5417.The method of claim 5415, further comprising producing fluid from atleast one heater well in which is positioned the heater of the one ormore heaters.
 5418. The method of claim 5415, further comprisingallowing heat to transfer from at least one of the heaters to theselected section to create thermal fractures in the formation, whereinthe thermal fractures substantially increase the permeability of theselected section.
 5419. The method of claim 5415, wherein the heat isprovided such that an average temperature in the selected section rangesfrom approximately about 270° C. to about 375° C.
 5420. The method ofclaim 5415, wherein at least one of the heaters comprises an electricalheater located in the formation.
 5421. The method of claim 5415, whereinat least one of the heaters is located in a heater well, and wherein atleast one of the heater wells comprises a conduit located in theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5422. The method of claim 5415, wherein atleast some of the heaters are arranged in a triangular pattern. 5423.The method of claim 5415, further comprising: monitoring a compositionof the produced mixture; and controlling a pressure in at least aportion of the formation to control the composition of the producedmixture.
 5424. The method of claim 5423, wherein the pressure iscontrolled by a valve proximate to a location where the mixture isproduced.
 5425. The method of claim 5423, wherein the pressure iscontrolled such that pressure proximate to one or more of the heaters isgreater than a pressure proximate to a location where the mixture isproduced.
 5426. The method of claim 5415 wherein an average distancebetween heaters is between about 2 m and about 8 m.
 5427. A method fortreating hydrocarbons in at least a portion of a hydrocarbon containingformation, wherein the portion has an average permeability of less thanabout 10 millidarcy, comprising: providing heat from one or more heatersto the formation; allowing the heat to transfer from one or more of theheaters to a selected first section of the formation such that heat fromthe heaters creates a pyrolysis zone wherein at least some hydrocarbonsare pyrolyzed within the first selected section, and allowing the heatto transfer from one or more of the heaters to a selected second sectionof the formation such that heat from the heaters heats at least somehydrocarbons within the selected second section to a temperature lessthan the average temperature within the pyrolysis zone; and producing amixture comprising hydrocarbons from the formation.
 5428. The method ofclaim 5427, wherein the one or more heaters comprise at least twoheaters, and wherein superposition of heat from the at least two heaterspyrolyzes at least some hydrocarbons within the selected first sectionof the formation, and wherein superposition of heat from the at leasttwo heaters heats at least some hydrocarbons within the selected secondsection to a temperature less than the average temperature within thepyrolysis zone.
 5429. The method of claim 5427, wherein at least someheated hydrocarbons within the selected second section flow into thepyrolysis zone.
 5430. The method of claim 5427, wherein the heatdecreases the viscosity of at least some of the hydrocarbons in theselected second section.
 5431. The method of claim 5427, furthercomprising allowing heat to transfer from at least one of the heaters tothe selected first section to create thermal fractures in the formation,wherein the thermal fractures substantially increase the permeability ofthe selected first section.
 5432. The method of claim 5427, furthercomprising allowing heat to transfer from at least one of the heaters tothe selected second section to create thermal fractures in theformation, wherein the thermal fractures substantially increase thepermeability of the selected second section.
 5433. The method of claim5427, wherein the heat is provided such that an average temperature inthe selected first section ranges from approximately about 270° C. toabout 375° C.
 5434. The method of claim 5427, wherein the heat isprovided such that an average temperature in the selected second sectionranges from approximately about 180° C. to about 250° C.
 5435. Themethod of claim 5427, wherein a viscosity of at least some of thehydrocarbons in the selected second section ranges from approximatelyabout 20 centipoise to about 1000 centipoise.
 5436. The method of claim5427, wherein at least one of the heaters comprises an electrical heaterlocated in the formation.
 5437. The method of claim 5427, wherein atleast one of the heaters is located in a heater well, and wherein atleast one of the heater wells comprises a conduit located in theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5438. The method of claim 5427, furthercomprising: monitoring a composition of the produced mixture; andcontrolling a pressure in at least a portion of the formation to controlthe composition of the produced mixture.
 5439. The method of claim 5438,wherein the pressure is controlled by a valve proximate to a locationwhere the mixture is produced.
 5440. The method of claim 5438, whereinthe pressure is controlled such that pressure proximate to one or moreof the heaters is greater than a pressure proximate to a location wherethe fluid is produced.
 5441. The method of claim 5427, wherein thepressure in the selected second section is substantially greater thanthe pressure in the selected first section.
 5442. The method of claim5427, wherein at least some of the heaters are arranged in a triangularpattern.
 5443. The method of claim 5427, wherein an average distancebetween heaters in the selected first section is less than an averagedistance between heaters in the selected second section.
 5444. Themethod of claim 5427, wherein the heat is provided to the selected firstsection before heat is provided to the selected second section. 5445.The method of claim 5427, wherein the selected first section comprisesat least one production well.
 5446. The method of claim 5427, wherein anaverage distance between heaters in the selected first section isbetween about 2 m and about 10 m.
 5447. The method of claim 5427,wherein an average distance between heaters in the selected secondsection is between about 5 m and about 20 m.
 5448. The method of claim5427, wherein the selected first section comprises a planar region.5449. The method of claim 5427, wherein at least one row of the heatersprovides heat to the planar region.
 5450. The method of claim 5449wherein a length of a row is between about 75 m and about 125 m. 5451.The method of claim 5448, wherein the planar region comprises a verticalhydraulic fracture.
 5452. The method of claim 5451, wherein a width ofthe vertical hydraulic fracture is between about 0.3 cm and about 2.5cm.
 5453. The method of claim 5451, wherein a length of the verticalhydraulic fracture is between about 75 m and about 125 m.
 5454. Themethod of claim 5427, wherein at least one ring comprising the heatersprovides heat to the selected first section.
 5455. The method of claim5454, wherein at least one ring comprising the heaters provides heat tothe selected second section.
 5456. The method of claim 5454, wherein thering comprises a polygon.
 5457. The method of claim 5454, wherein thering comprises a regular polygon.
 5458. The method of claim 5454,wherein the ring comprises a hexagon.
 5459. The method of claim 5454,wherein the ring comprises a triangle.
 5460. A method for treatinghydrocarbons in at least a portion of a hydrocarbon containingformation, wherein the portion has an average permeability of less thanabout 10 millidarcy, comprising: providing heat from three or moreheaters to the formation; allowing the heat to transfer from three ormore of the heaters to a selected section of the formation such thatheat from the heaters pyrolyzes at least some hydrocarbons within theselected section, and at least three of the heaters are arranged in asubstantially triangular pattern; and producing a mixture comprisinghydrocarbons from the formation.
 5461. The method of claim 5460, whereinsuperposition of heat from at least the three heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 5462.The method of claim 5460, wherein the mixture is produced from aproduction well located in a triangular region created by at least threeheaters.
 5463. The method of claim 5460, further comprising allowingheat to transfer from at least one of the heaters to the selectedsection to create thermal fractures in the formation, wherein thethermal fractures substantially increase the permeability of theselected section.
 5464. The method of claim 5460, wherein the heat isprovided such that an average temperature in the selected section rangesfrom approximately about 270° C. to about 375° C.
 5465. The method ofclaim 5460, wherein at least one of the heaters comprises a electricalheater located in the formation.
 5466. The method of claim 5460, whereinat least one of the heaters is located in a heater well, and wherein atleast one of the heater wells comprises a conduit located in theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5467. The method of claim 5460, wherein atleast some of the heaters are arranged in a triangular pattern. 5468.The method of claim 5460, further comprising: monitoring a compositionof the produced mixture; and controlling a pressure in at least aportion of the formation to control the composition of the producedmixture.
 5469. The method of claim 5468, wherein the pressure iscontrolled by a valve proximate to a location where the mixture isproduced.
 5470. The method of claim 5468, wherein the pressure iscontrolled such that pressure proximate to one or more of the heaters isgreater than a pressure proximate to a location where the fluid isproduced.
 5471. The method of claim 5460, wherein an average distancebetween heaters is between about 2 m and about 8 m.
 5472. A systemconfigurable to heat a hydrocarbon containing formation, comprising: aconduit configurable to be placed within an opening in the formation; aconductor configurable to be placed within the conduit, wherein theconductor is further configurable to provide heat to at least a portionof the formation during use; at least one centralizer configurable to becoupled to the conductor, wherein at least one centralizer inhibitsmovement of the conductor within the conduit during use; and wherein thesystem is configurable to allow heat to transfer from the conductor to asection of the formation during use.
 5473. The system of claim 5472,wherein at least one centralizer comprises electrically-insulatingmaterial.
 5474. The system of claim 5472, wherein at least onecentralizer is configurable to inhibit arcing between the conductor andthe conduit.
 5475. The system of claim 5472, wherein at least onecentralizer comprises ceramic material.
 5476. The system of claim 5472,wherein at least one centralizer comprises at least one recess, whereinat least one recess is placed at a junction of at least one centralizerand the first conductor, wherein at least one protrusion is formed onthe first conductor at the junction to maintain a location of at leastone centralizer on the first conductor, and wherein at least oneprotrusion resides substantially within at least one recess.
 5477. Thesystem of claim 5476, wherein at least one protrusion comprises a weld.5478. The system of claim 5476, wherein an electrically-insulatingmaterial substantially covers at least one recess.
 5479. The system ofclaim 5476, wherein a thermal plasma applied coating substantiallycovers at least one recess.
 5480. The system of claim 5476, wherein athermal plasma applied coating comprises alumina.
 5481. The system ofclaim 5472, wherein the system is further configurable to allow at leastsome hydrocarbons to pyrolyze in the heated section of the formationduring use.
 5482. The system of claim 5472, further comprising aninsulation layer configurable to be coupled to at least a portion of theconductor or at least one centralizer.
 5483. The system of claim 5472,wherein at least one centralizer comprises a neck portion.
 5484. Thesystem of claim 5472, wherein at least one centralizer comprises one ormore grooves.
 5485. The system of claim 5472, wherein at least onecentralizer comprises at least two portions, and wherein the portionsare configurable to be coupled to the conductor to form at least onecentralizer placed on the conductor.
 5486. The system of claim 5472,wherein a thickness of the conductor is greater adjacent to a lean zonein the formation than a thickness of the conductor adjacent to a richzone in the formation such that more heat is provided to the rich zone.5487. The system of claim 5472, wherein the system is configured to heata hydrocarbon containing formation, and wherein the system comprises: aconduit configured to be placed within an opening in the formation; aconductor configured to be placed within the conduit, wherein theconductor is further configured to provide heat to at least a portion ofthe formation during use; at least one centralizer configured to becoupled to the conductor, wherein at least one centralizer inhibitsmovement of the conductor within the conduit during use; and wherein thesystem is configured to allow heat to transfer from the conductor to asection of the formation during use.
 5488. The system of claim 5472,wherein the system heats a hydrocarbon containing formation, and whereinthe system comprises: a conduit placed within an opening in theformation; a conductor placed within the conduit, wherein the conductorprovides heat to at least a portion of the formation; at least onecentralizer coupled to the conductor, wherein at least one centralizerinhibits movement of the conductor within the conduit; and wherein thesystem allows heat to transfer from the conductor to a section of theformation.
 5489. The system of claim 5472, wherein the system isconfigurable to be removed from the opening in the formation.
 5490. Thesystem of claim 5472, further comprising a moveable thermocouple. 5491.The system of claim 5472, further comprising an isolation block.
 5492. Asystem configurable to heat a hydrocarbon containing formation,comprising: a conduit configurable to be placed within an opening in theformation; a conductor configurable to be placed within the conduit,wherein the conductor is further configurable to provide heat to atleast a portion of the formation during use; at least one centralizerconfigurable to be coupled to the conductor, wherein at least onecentralizer inhibits movement of the conductor within the conduit duringuse wherein the system is configurable to allow heat to transfer fromthe conductor to a section of the formation during use; and wherein thesystem is configurable to be removed from the opening in the formation.5493. An in situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to a conductor to provideheat to at least a portion of the formation, wherein the conductor isplaced within a conduit, wherein at least one centralizer is coupled tothe conductor to inhibit movement of the conductor within the conduit,and wherein the conduit is placed within an opening in the formation;and allowing the heat to transfer from the first conductor to a sectionof the formation.
 5494. The method of claim 5493, further comprisingpyrolyzing at least some hydrocarbons in the section of the formation.5495. The method of claim 5493, further comprising inhibiting arcingbetween the conductor and the conduit.
 5496. A system configurable toheat a hydrocarbon containing formation, comprising: a conduitconfigurable to be placed within an opening in the formation; aconductor configurable to be placed within a conduit, wherein theconductor is further configurable to provide heat to at least a portionof the formation during use; an insulation layer coupled to at least aportion of the conductor, wherein the insulation layer electricallyinsulates at least a portion of the conductor from the conduit duringuse; and wherein the system is configurable to allow heat to transferfrom the conductor to a section of the formation during use
 5497. Thesystem of claim 5496, wherein the insulation layer comprises a spiralinsulation layer.
 5498. The system of claim 5496, wherein the insulationlayer comprises at least one metal oxide.
 5499. The system of claim5496, wherein the insulation layer comprises at least one alumina oxide.5500. The system of claim 5496, wherein the insulation layer isconfigurable to be fastened to the conductor with a high temperatureglue.
 5501. The system of claim 5496, wherein the system is furtherconfigurable to allow at least some hydrocarbons to pyrolyze in theheated section of the formation during use.
 5502. The system of claim5496, wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a conduit configured to beplaced within an opening in the formation; a conductor configured to beplaced within a conduit, wherein the conductor is further configured toprovide heat to at least a portion of the formation during use; aninsulation layer coupled to at least a portion of the conductor, whereinthe insulation layer electrically insulates at least a portion of theconductor from the conduit during use; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 5503. The system of claim 5496, wherein thesystem heats a hydrocarbon containing formation, and wherein the systemcomprises: a conduit placed within an opening in the formation; aconductor placed within a conduit, wherein the conductor provides heatto at least a portion of the formation; an insulation layer coupled toat least a portion of the conductor, wherein the insulation layerelectrically insulates at least a portion of the conductor from theconduit; and wherein the system allows heat to transfer from theconductor to a section of the formation.
 5504. An in situ method forheating a hydrocarbon containing formation, comprising: applying anelectrical current to a conductor to provide heat to at least a portionof the formation, wherein the conductor is placed within a conduit,wherein an insulation layer is coupled to at least a portion of theconductor to electrically insulate at least a portion of the conductorfrom the conduit, and wherein the conduit is placed within an opening inthe formation; and allowing the heat to transfer from the firstconductor to a section of the formation.
 5505. The method of claim 5504,further comprising pyrolyzing at least some hydrocarbons in the sectionof the formation.
 5506. The method of claim 5504, further comprisinginhibiting arcing between the conductor and the conduit.
 5507. A methodfor making a conductor-in-conduit heater for a hydrocarbon containingformation, comprising: placing at least one protrusion on a conductor;placing at least one centralizer on the conductor; and placing theconductor within a conduit to form a conductor-in-conduit heater,wherein at least one centralizer maintains a location of the conductorwithin the conduit.
 5508. The method of claim 5507, wherein at least onecentralizer comprises at least two portions, and wherein the portionsare coupled to the conductor to form at least one centralizer placed onthe conductor.
 5509. The method of claim 5507, further comprisingplacing the conductor-in-conduit heater in an opening in a hydrocarboncontaining formation.
 5510. The method of claim 5507, further comprisingcoupling an insulation layer on the conductor, wherein the insulationlayer is configured to electrically insulate at least a portion of theconductor from the conduit.
 5511. The method of claim 5507, furthercomprising providing heat from the conductor-in-conduit heater to atleast a portion of the formation.
 5512. The method of claim 5507,further comprising pyrolyzing at least some hydrocarbons in a selectedsection of the formation.
 5513. The method of claim 5507, furthercomprising producing a mixture from a selected section of the formation.5514. The method of claim 5507, wherein the conductor-in-conduit heateris configurable to provide heat to the hydrocarbon containing formation.5515. The method of claim 5507, wherein at least one centralizercomprises at least one recess placed at a junction of at least onecentralizer on the conductor, and wherein at least one protrusionresides substantially within at least one recess.
 5516. The method ofclaim 5515, further comprising at least partially covering at least onerecess with an electrically-insulating material.
 5517. The method ofclaim 5515, further comprising spraying an electrically-insulatingmaterial to at least partially cover at least one recess.
 5518. Themethod of claim 5507, wherein placing at least one protrusion on theconductor comprises welding at least one protrusion on the conductor.5519. The method of claim 5507, further comprising coiling theconductor-in-conduit heater on a spool after forming the heater. 5520.The method of claim 5507, further comprising uncoiling the heater fromthe spool while placing the heater in an opening in the formation. 5521.The method of claim 5507, wherein placing the conductor within a conduitcomprises placing the conductor within a conduit that has been placed inan opening in the formation.
 5522. The method of claim 5507, furthercomprising coupling the conductor-in-conduit heater to at least oneadditional conductor-in-conduit heater.
 5523. The method of claim 5507,wherein the conductor-in-conduit heater is configurable to be installedinto an opening in a hydrocarbon containing formation.
 5524. The methodof claim 5507, wherein the conductor-in-conduit heater is configurableto be removed from an opening in a hydrocarbon containing formation.5525. The method of claim 5507, wherein the conductor-in-conduit heateris configurable to heat to a section of the hydrocarbon containingformation, and wherein the heat pyrolyzes at least some hydrocarbons inthe section of the formation during use.
 5526. The method of claim 5507,wherein a thickness of the conductor configurable to be placed adjacentto a lean zone in the formation is greater than a thickness of theconductor configurable to be placed adjacent to a rich zone in theformation such that more heat is provided to the rich zone during use.5527. A method of installing a conductor-in-conduit heater of a desiredlength in a hydrocarbon containing formation, comprising: assembling aconductor-in-conduit heater of a desired length, comprising: placing aconductor within a conduit to form a conductor-in-conduit heater; andcoupling the conductor-in-conduit heater to at least one additionalconductor-in-conduit heater to form a conductor-in-conduit heater of thedesired length, wherein the conductor is electrically coupled to theconductor of at least one additional conductor-in-conduit heater and theconduit is electrically coupled to the conduit of at least oneadditional conductor-in-conduit heater; coiling the conductor-in-conduitheater of the desired length after forming the heater; and placing theconductor-in-conduit heater of the desired length in an opening in ahydrocarbon containing formation.
 5528. The method of claim 5527,wherein the conductor-in-conduit heater is configurable to provide heatto the hydrocarbon containing formation.
 5529. The method of claim 5527,wherein the conductor-in-conduit heater of the desired length isremovable from the opening in the hydrocarbon containing formation.5530. The method of claim 5527, further comprising uncoiling theconductor-in-conduit heater of the desired length while placing theheater in the opening.
 5531. The method of claim 5527, furthercomprising placing at least one centralizer on the conductor.
 5532. Themethod of claim 5527, further comprising placing at least onecentralizer on the conductor, wherein at least one centralizer inhibitsmovement of the conductor within the conduit.
 5533. The method of claim5527, further comprising placing an insulation layer on at least aportion of the conductor.
 5534. The method of claim 5527, furthercomprising coiling the conductor-in-conduit heater.
 5535. The method ofclaim 5527, further comprising testing the conductor-in-conduit heaterand coiling the heater.
 5536. The method of claim 5527, wherein couplingthe conductor-in-conduit heater to at least one additionalconductor-in-conduit heater comprises welding the conductor-in-conduitheater to at least one additional conductor-in-conduit heater.
 5537. Themethod of claim 5527, wherein coupling the conductor-in-conduit heaterto at least one additional conductor-in-conduit heater comprisesshielded active gas welding the conductor-in-conduit heater to at leastone additional conductor-in-conduit heater.
 5538. The method of claim5527, wherein coupling the conductor-in-conduit heater to at least oneadditional conductor-in-conduit heater comprises shielded active gaswelding the conductor-in-conduit heater to at least one additionalconductor-in-conduit heater, and wherein using shielded active gaswelding inhibits changes in the grain structure of the conductor orconduit during coupling.
 5539. The method of claim 5527, wherein theassembling of the conductor-in-conduit heater of the desired length isperformed at a location proximate the hydrocarbon containing formation.5540. The method of claim 5527, wherein the assembling of theconductor-in-conduit heater of the desired length takes placesufficiently proximate the hydrocarbon containing formation such thatthe conductor-in-conduit heater can be placed directly in an opening ofthe formation after the heater is assembled.
 5541. The method of claim5527, further comprising coupling at least one substantially lowresistance conductor to the conductor-in-conduit heater of the desiredlength, wherein at least one substantially low resistance conductor isconfigured to be placed in an overburden of the formation.
 5542. Themethod of claim 5541, further comprising coupling at least oneadditional substantially low resistance conductor to at least onesubstantially low resistance conductor.
 5543. The method of claim 5541,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises coupling a threaded end of at least one additionalsubstantially low resistance conductor to a threaded end of at least onesubstantially low resistance conductor.
 5544. The method of claim 5541,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises welding at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor.
 5545. The method of claim 5541, wherein at least onesubstantially low resistance conductor is coupled to theconductor-in-conduit heater of the desired length during assembling ofthe heater of the desired length.
 5546. The method of claim 5541,wherein at least one substantially low resistance conductor is coupledto the conductor-in-conduit heater of the desired length afterassembling of the heater of the desired length.
 5547. The method ofclaim 5527, further comprising transporting the coiledconductor-in-conduit heater of the desired length on a cart or trainfrom an assembly location to the opening in the hydrocarbon containingformation.
 5548. The method of claim 5547, wherein the cart or train canbe further used to transport more than one conductor-in-conduit heaterof the desired length to more than one opening in the hydrocarboncontaining formation.
 5549. The method of claim 5527, wherein thedesired length comprises a length determined for using theconductor-in-conduit heater in a selected opening in the hydrocarboncontaining formation.
 5550. The method of claim 5527, further comprisingtreating the conductor to increase an emissivity of the conductor. 5551.The method of claim 5550, wherein treating the conductor comprisesroughening the surface of the conductor.
 5552. The method of claim 5550,wherein treating the conductor comprises heating the conductor to atemperature above about 750° C. in an oxidizing fluid atmosphere. 5553.The method of claim 5527, further comprising treating the conduit toincrease an emissivity of the conduit.
 5554. The method of claim 5527,further comprising coating at least a portion of the conductor or atleast a portion of the conduit during assembly of theconductor-in-conduit heater.
 5555. The method of claim 5527, furthercomprising placing an insulation layer on at least a portion of theconductor-in-conduit heater prior to placing the heater in the openingin the hydrocarbon containing formation.
 5556. The method of claim 5555,wherein the insulation layer comprises a spiral insulation layer. 5557.The method of claim 5555, wherein the insulation layer comprises atleast one metal oxide.
 5558. The method of claim 5555, furthercomprising fastening at least a portion of the insulation layer to atleast a portion of the conductor-in-conduit heater with a hightemperature glue.
 5559. The method of claim 5527, further comprisingproviding heat from the conductor-in-conduit heater of the desiredlength to at least a portion of the formation.
 5560. The method of claim5527, wherein a thickness of the conductor configurable to be placedadjacent to a lean zone in the formation is greater than a thickness ofthe conductor configurable to be placed adjacent to a rich zone in theformation such that more heat is provided to the rich zone during use5561. The method of claim 5527, further comprising pyrolyzing at leastsome hydrocarbons in a selected section of the formation.
 5562. Themethod of claim 5527, further comprising producing a mixture from aselected section of the formation.
 5563. A method for making aconductor-in-conduit heater configurable to be used to heat ahydrocarbon containing formation, comprising: placing a conductor withina conduit to form a conductor-in-conduit heater; and shielded active gaswelding the conductor-in-conduit heater to at least one additionalconductor-in-conduit heater to form a conductor-in-conduit heater of adesired length, wherein the conductor is electrically coupled to theconductor of at least one additional conductor-in-conduit heater and theconduit is electrically coupled to the conduit of at least oneadditional conductor-in-conduit heater; and wherein theconductor-in-conduit heater is configurable to be placed in an openingin the hydrocarbon containing formation, and wherein theconductor-in-conduit heater is further configurable to heat a section ofthe hydrocarbon containing formation during use.
 5564. The method ofclaim 5563, further comprising providing heat from theconductor-in-conduit heater of the desired length to at least a portionof the formation.
 5565. The method of claim 5563, further comprisingpyrolyzing at least some hydrocarbons in a selected section of theformation.
 5566. The method of claim 5563, further comprising producinga mixture from a selected section of the formation.
 5567. The method ofclaim 5563, wherein the conductor and the conduit comprise stainlesssteel.
 5568. The method of claim 5563, wherein the conduit comprisesstainless steel.
 5569. The method of claim 5563, wherein the heater isconfigurable to be removed from the formation.
 5570. The method of claim5563, further comprising providing a reducing gas during welding. 5571.The method of claim 5563, wherein the reducing gas comprises molecularhydrogen.
 5572. The method of claim 5563, further comprising providing areducing gas during welding such that welding occurs in an environmentcomprising less than about 25% reducing gas by volume.
 5573. The methodof claim 5563, further comprising providing a reducing gas duringwelding such that welding occurs in an environment comprising about 10%reducing gas by volume.
 5574. A system configurable to heat ahydrocarbon containing formation, comprising: a conduit configurable tobe placed within an opening in the formation; a conductor configurableto be placed within the conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use, and wherein the conductor comprises at least two conductorsections coupled by shielded active gas welding; and wherein the systemis configurable to allow heat to transfer from the conductor to asection of the formation during use.
 5575. The system of claim 5574,wherein the conduit comprises at least two conduit sections coupled byshielded active gas welding.
 5576. The system of claim 5574, wherein thesystem is further configurable to allow at least some hydrocarbons topyrolyze in the heated section of the formation during use.
 5577. Thesystem of claim 5574, wherein the system is configured to heat ahydrocarbon containing formation, and wherein the system comprises: aconduit configured to be placed within an opening in the formation; aconductor configured to be placed within the conduit, wherein theconductor is further configured to provide heat to at least a portion ofthe formation during use, and wherein the conductor comprises at leasttwo conductor sections coupled by shielded active gas welding; andwherein the system is configured to allow heat to transfer from theconductor to a section of the formation during use.
 5578. The system ofclaim 5574, wherein the system heats a hydrocarbon containing formation,and wherein the system comprises: a conduit placed within an opening inthe formation; a conductor placed within the conduit, wherein theconductor provides heat to at least a portion of the formation duringuse, and wherein the conductor comprises at least two conductor sectionscoupled by shielded active gas welding; and wherein the system allowsheat to transfer from the conductor to a section of the formation duringuse.
 5579. The system of claim 5574, wherein the conductor-in-conduitheater is configurable to be removed from the formation.
 5580. A methodfor installing a heater of a desired length in a hydrocarbon containingformation, comprising: assembling a heater of a desired length, whereinthe assembling of the heater of the desired length is performed at alocation proximate the hydrocarbon containing formation; coiling theheater of the desired length after forming the heater; and placing theheater of the desired length in an opening in a hydrocarbon containingformation, wherein placing the heater in the opening comprises uncoilingthe heater while placing the heater in the opening.
 5581. The method ofclaim 5580, wherein the heater is configurable to heat a section of thehydrocarbon containing formation.
 5582. The method of claim 5581,wherein the heat pyrolyzes at least some hydrocarbons in the section ofthe formation during use.
 5583. The method of claim 5580, furthercomprising coupling at least one substantially low resistance conductorto the heater of the desired length, wherein at least one substantiallylow resistance conductor is configured to be placed in an overburden ofthe formation.
 5584. The method of claim 5583, further comprisingcoupling at least one additional substantially low resistance conductorto at least one substantially low resistance conductor.
 5585. The methodof claim 5583, further comprising coupling at least one additionalsubstantially low resistance conductor to at least one substantially lowresistance conductor, wherein coupling at least one additionalsubstantially low resistance conductor to at least one substantially lowresistance conductor comprises coupling a threaded end of at least oneadditional substantially low resistance conductor to a threaded end ofat least one substantially low resistance conductor.
 5586. The method ofclaim 5583, further comprising coupling at least one additionalsubstantially low resistance conductor to at least one substantially lowresistance conductor, wherein coupling at least one additionalsubstantially low resistance conductor to at least one substantially lowresistance conductor comprises welding at least one additionalsubstantially low resistance conductor to at least one substantially lowresistance conductor.
 5587. The method of claim 5580, further comprisingtransporting the heater of the desired length on a cart or train from anassembly location to the opening in the hydrocarbon containingformation.
 5588. The method of claim 5587, wherein the cart or train canbe further used to transport more than one heater to more than oneopening in the hydrocarbon containing formation.
 5589. The method ofclaim 5587, wherein the heater is configurable to removable from theopening.
 5590. A method for installing a heater of a desired length in ahydrocarbon containing formation, comprising: assembling a heater of adesired length, wherein the assembling of the heater of the desiredlength is performed at a location proximate the hydrocarbon containingformation; coiling the heater of the desired length after forming theheater; placing the heater of the desired length in an opening in ahydrocarbon containing formation, wherein placing the heater in theopening comprises uncoiling the heater while placing the heater in theopening; and wherein the heater is configurable to be removed from theopening.
 5591. The method of claim 5590, wherein the heater isconfigurable to heat a section of the hydrocarbon containing formation.5592. The method of claim 5591, wherein the heat pyrolyzes at least somehydrocarbons in the section of the formation during use.
 5593. Themethod of claim 5590, further comprising coupling at least onesubstantially low resistance conductor to the heater of the desiredlength, wherein at least one substantially low resistance conductor isconfigured to be placed in an overburden of the formation.
 5594. Themethod of claim 5593, further comprising coupling at least oneadditional substantially low resistance conductor to at least onesubstantially low resistance conductor.
 5595. The method of claim 5593,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises coupling a threaded end of at least one additionalsubstantially low resistance conductor to a threaded end of at least onesubstantially low resistance conductor.
 5596. The method of claim 5593,further comprising coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor, wherein coupling at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor comprises welding at least one additional substantially lowresistance conductor to at least one substantially low resistanceconductor.
 5597. The method of claim 5590, further comprisingtransporting the heater of the desired length on a cart or train from anassembly location to the opening in the hydrocarbon containingformation.
 5598. The method of claim 5590, wherein removing the heatercomprises recoiling the heater.
 5599. The method of claim 5590, whereinthe heater can be removed from the opening and installed in an alternateopening in the formation.
 5600. A system configurable to heat ahydrocarbon containing formation, comprising: a conduit configurable tobe placed within an opening in the formation; a conductor configurableto be placed within a conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use; an electrically conductive material configurable to becoupled to at least a portion of the conductor, wherein the electricallyconductive material is configurable to lower an electrical resistance ofthe conductor in the overburden during use; and wherein the system isconfigurable to allow heat to transfer from the conductor to a sectionof the formation during use.
 5601. The system of claim 5600, furthercomprising an electrically conductive material configurable to becoupled to at least a portion of an inside surface of the conduit. 5602.The system of claim 5600, further comprising a substantially lowresistance conductor configurable to be electrically coupled to theconductor and the electrically conductive material during use, whereinthe substantially low resistance conductor is further configurable to beplaced within an overburden of the formation.
 5603. The system of claim5602, wherein the low resistance conductor comprises carbon steel. 5604.The system of claim 5600, wherein the electrically conductive materialcomprises metal tubing configurable to be clad to the conductor. 5605.The system of claim 5600, wherein the electrically conductive materialcomprises an electrically conductive coating configurable to be appliedto the conductor.
 5606. The system of claim 5600, wherein theelectrically conductive material comprises a thermal plasma appliedcoating.
 5607. The system of claim 5600, wherein the electricallyconductive material is configurable to be sprayed on the conductor.5608. The system of claim 5600, wherein the electrically conductivematerial comprises aluminum.
 5609. The system of claim 5600, wherein theelectrically conductive material comprises copper.
 5610. The system ofclaim 5600, wherein the electrically conductive material is configurableto reduce the electrical resistance of the conductor in the overburdenby a factor of greater than about
 3. 5611. The system of claim 5600,wherein the electrically conductive material is configurable to reducethe electrical resistance of the conductor in the overburden by a factorof greater than about
 15. 5612. The system of claim 5600, wherein thesystem is further configurable to allow at least some hydrocarbons topyrolyze in the heated section of the formation during use.
 5613. Thesystem of claim 5600, wherein the system is configured to heat ahydrocarbon containing formation, and wherein the system comprises: aconduit configured to be placed within an opening in the formation; aconductor configured to be placed within a conduit, wherein theconductor is further configured to provide heat to at least a portion ofthe formation during use; an electrically conductive material configuredto be coupled to the conductor, wherein the electrically conductivematerial is further configured to lower an electrical resistance of theconductor in the overburden during use; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 5614. The system of claim 5600, wherein thesystem heats a hydrocarbon containing formation, and wherein the systemcomprises: a conduit placed within an opening in the formation; aconductor placed within a conduit, wherein the conductor is providesheat to at least a portion of the formation during use; an electricallyconductive material coupled to the conductor, wherein the electricallyconductive material lowers an electrical resistance of the conductor inthe overburden during use; and wherein the system allows heat totransfer from the conductor to a section of the formation during use.5615. An in situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to a conductor to provideheat to at least a portion of the formation, wherein the conductor isplaced in a conduit, and wherein the conduit is placed in an opening inthe formation, and wherein the conductor is coupled to an electricallyconductive material; and allowing the heat to transfer from theconductor to a section of the formation.
 5616. The method of claim 5615,wherein the electrically conductive material comprises copper.
 5617. Themethod of claim 5615, further comprising coupling an electricallyconductive material to an inside surface of the conduit.
 5618. Themethod of claim 5615, wherein the electrically conductive materialcomprises metal tubing clad to the substantially low resistanceconductor.
 5619. The method of claim 5615, wherein the electricallyconductive material reduces an electrical resistance of thesubstantially low resistance conductor in the overburden.
 5620. Themethod of claim 5615, further comprising pyrolyzing at least somehydrocarbons within the formation.
 5621. A system configurable to heat ahydrocarbon containing formation, comprising: a conduit configurable tobe placed within an opening in the formation; a conductor configurableto be placed within a conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use, and wherein the conductor has been treated to increase anemissivity of at least a portion of a surface of the conductor; andwherein the system is configurable to allow heat to transfer from theconductor to a section of the formation during use.
 5622. The system ofclaim 5621, wherein at least a portion of the surface of the conductorhas been roughened to increase the emissivity of the conductor. 5623.The system of claim 5621, wherein the conductor has been heated to atemperature above about 750° C. in an oxidizing fluid atmosphere toincrease the emissivity of at least a portion of the surface of theconductor.
 5624. The system of claim 5621, wherein the conduit has beentreated to increase an emissivity of at least a portion of the surfaceof the conduit.
 5625. The system of claim 5621, further comprising anelectrically insulative, thermally conductive coating coupled to theconductor.
 5626. The system of claim 5625, wherein the electricallyinsulative, thermally conductive coating is configurable to electricallyinsulate the conductor from the conduit.
 5627. The system of claim 5625,wherein the electrically insulative, thermally conductive coatinginhibits emissivity of the conductor from decreasing.
 5628. The systemof claim 5625, wherein the electrically insulative, thermally conductivecoating substantially increases an emissivity of the conductor. 5629.The system of claim 5625, wherein the electrically insulative, thermallyconductive coating comprises silicon oxide.
 5630. The system of claim5625, wherein the electrically insulative, thermally conductive coatingcomprises aluminum oxide.
 5631. The system of claim 5625, wherein theelectrically insulative, thermally conductive coating comprisesrefractive cement.
 5632. The system of claim 5625, wherein theelectrically insulative, thermally conductive coating is sprayed on theconductor.
 5633. The system of claim 5621, wherein the system is furtherconfigurable to allow at least some hydrocarbons to pyrolyze in theheated section of the formation during use.
 5634. The system of claim5621, wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a conduit configured to beplaced within an opening in the formation; a conductor configured to beplaced within a conduit, wherein the conductor is further configured toprovide heat to at least a portion of the formation during use, andwherein the conductor has been treated to increase an emissivity of atleast a portion of a surface of the conductor; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 5635. The system of claim 5621, wherein thesystem heats a hydrocarbon containing formation, and wherein the systemcomprises: a conduit placed within an opening in the formation; aconductor placed within a conduit, wherein the conductor provides heatto at least a portion of the formation during use, and wherein theconductor has been treated to increase an emissivity of at least aportion of a surface of the conductor; and wherein the system allowsheat to transfer from the conductor to a section of the formation duringuse.
 5636. A heater configurable to heat a hydrocarbon containingformation, comprising: a conduit configurable to be placed within anopening in the formation; and a conductor configurable to be placedwithin a conduit, wherein the conductor is further configurable toprovide heat to at least a portion of the formation during use, andwherein the conductor has been treated to increase an emissivity of atleast a portion of a surface of the conductor.
 5637. The heater of claim5636, wherein at least a portion of the surface of the conductor hasbeen roughened to increase the emissivity the conductor.
 5638. Theheater of claim 5636, wherein the conductor has been heated to atemperature above about 750° C. in an oxidizing fluid atmosphere toincrease the emissivity of at least at least a portion of the surface ofthe conductor.
 5639. The heater of claim 5636, wherein the conduit hasbeen treated to increase an emissivity of at least a portion of thesurface of the conduit.
 5640. The heater of claim 5636, furthercomprising an electrically insulative, thermally conductive coatingplaced on the conductor.
 5641. The heater of claim 5640, wherein theelectrically insulative, thermally conductive coating is configurable toelectrically insulate the conductor from the conduit.
 5642. The heaterof claim 5640, wherein the electrically insulative, thermally conductivecoating substantially maintains an emissivity of the conductor. 5643.The heater of claim 5640, wherein the electrically insulative, thermallyconductive coating substantially increases an emissivity of theconductor.
 5644. The heater of claim 5640, wherein the electricallyinsulative, thermally conductive coating comprises silicon oxide. 5645.The heater of claim 5640, wherein the electrically insulative, thermallyconductive coating comprises aluminum oxide.
 5646. The heater of claim5640, wherein the electrically insulative, thermally conductive coatingcomprises refractive cement.
 5647. The heater of claim 5640, wherein theelectrically insulative, thermally conductive coating is sprayed on theconductor.
 5648. The heater of claim 5636, wherein the conductor isfurther configurable to provide heat to at least a portion of theformation during use such that at least some hydrocarbons pyrolyze inthe heated section of the formation during use.
 5649. The heater ofclaim 5636, wherein the heater is configured to heat a hydrocarboncontaining formation, and wherein the system comprises: a conduitconfigured to be placed within an opening in the formation; a conductorconfigured to be placed within a conduit, wherein the conductor isfurther configured to provide heat to at least a portion of theformation during use, and wherein the conductor has been treated toincrease an emissivity of at least a portion of a surface of theconductor.
 5650. The heater of claim 5636, wherein the heater heats ahydrocarbon containing formation, and wherein the system comprises: aconduit placed within an opening in the formation; a conductor placedwithin a conduit, wherein the conductor provides heat to at least aportion of the formation, and wherein the conductor has been treated toincrease an emissivity of at least a portion of a surface of theconductor.
 5651. A method for forming an increased emissivityconductor-in-conduit heater, comprising: treating a surface of aconductor to increase an emissivity of at least the surface of theconductor; placing the conductor within a conduit to form aconductor-in-conduit heater; and wherein the conductor-in-conduit heateris configurable to heat a hydrocarbon containing formation.
 5652. Themethod of claim 5651, wherein treating the surface of the conductorcomprises roughening at least a portion of the surface of the conductor.5653. The method of claim 5651, wherein treating the surface of theconductor comprises heating the conductor to a temperature above about750° C. in an oxidizing fluid atmosphere.
 5654. The method of claim5651, further comprising treating a surface of the conduit to increasean emissivity of at least a portion of the surface of the conduit. 5655.The method of claim 5651, further comprising placing theconductor-in-conduit heater of the desired length in an opening in ahydrocarbon containing formation.
 5656. The method of claim 5651,further comprising assembling a conductor-in-conduit heater of a desiredlength, the assembling comprising: coupling the conductor-in-conduitheater to at least one additional conductor-in-conduit heater to form aconductor-in-conduit heater of a desired length, wherein the conductoris electrically coupled to the conductor of at least one additionalconductor-in-conduit heater and the conduit is electrically coupled tothe conduit of at least one additional conductor-in-conduit heater;coiling the conductor-in-conduit heater of the desired length afterforming the heater; and placing the conductor-in-conduit heater of thedesired length in an opening in a hydrocarbon containing formation.5657. The method of claim 5651, wherein the conductor-in-conduit heateris configurable to heat to a section of the hydrocarbon containingformation, and wherein the heat pyrolyzes at least some hydrocarbons inthe section of the formation during use.
 5658. A system configurable toheat a hydrocarbon containing formation, comprising: a heaterconfigurable to be placed in an opening in the formation, wherein theheater is further configurable to provide heat to at least a portion ofthe formation during use; an expansion mechanism configurable to becoupled to the heater, wherein the expansion mechanism is configurableto allow for movement of the heater during use; and wherein the systemis configurable to allow heat to transfer to a section of the formationduring use.
 5659. The system of claim 5658, wherein the expansionmechanism is configurable to allow for expansion of the heater duringuse.
 5660. The system of claim 5658, wherein the expansion mechanism isconfigurable to allow for contraction of the heater during use. 5661.The system of claim 5658, wherein the expansion mechanism isconfigurable to allow for expansion of at least one component of theheater during use.
 5662. The system of claim 5658, wherein the expansionmechanism is configurable to allow for expansion and contraction of theheater within a wellbore during use.
 5663. The system of claim 5658,wherein the expansion mechanism comprises spring loading.
 5664. Thesystem of claim 5658, wherein the expansion mechanism comprises anaccordion mechanism.
 5665. The system of claim 5658, wherein theexpansion mechanism is configurable to be coupled to a bottom of theheater.
 5666. The system of claim 5658, wherein the heater isconfigurable to allow at least some hydrocarbons to pyrolyze in theheated section of the formation during use.
 5667. The system of claim5658, wherein the system is configured to heat a hydrocarbon containingformation, and wherein the system comprises: a heater configured to beplaced in an opening in the formation, wherein the heater is furtherconfigured to provide heat to at least a portion of the formation duringuse; an expansion mechanism configured to be coupled to the heater,wherein the expansion mechanism is configured to allow for movement ofthe heater during use; and wherein the system is configured to allowheat to transfer to a section of the formation during use.
 5668. Thesystem of claim 5658, wherein the system heats a hydrocarbon containingformation, and wherein the system comprises: a heater placed in anopening in the formation, wherein the heater provides heat to at least aportion of the formation during use; an expansion mechanism coupled tothe heater, wherein the expansion mechanism allows for movement of theheater during use; and wherein the system allows heat to transfer to asection of the formation during use.
 5669. The system of claim 5658,wherein the heater is removable.
 5670. A system configurable to provideheat to a hydrocarbon containing formation, comprising: a conduitpositionable in at least a portion of an opening in the formation,wherein a first end of the opening contacts an earth surface at a firstlocation, and wherein a second end of the opening contacts the earthsurface at a second location; and an oxidizer configurable to provideheat to a selected section of the formation by transferring heat throughthe conduit.
 5671. The system of claim 5670, wherein heat from theoxidizer pyrolyzes at least some hydrocarbons in the selected section.5672. The system of claim 5670, wherein the conduit is positioned in theopening.
 5673. The system of claim 5670, wherein the oxidizer ispositionable in the conduit.
 5674. The system of claim 5670, wherein theoxidizer is positioned in the conduit, and wherein the oxidizer isconfigured to heat the selected section.
 5675. The system of claim 5670,wherein the oxidizer comprises a ring burner.
 5676. The system of claim5670, wherein the oxidizer comprises an inline burner.
 5677. The systemof claim 5670, wherein the oxidizer is configurable to provide heat inthe conduit.
 5678. The system of claim 5670, further comprising anannulus formed between a wall of the conduit and a wall of the opening.5679. The system of claim 5670, wherein the oxidizer comprises a firstoxidizer and a second oxidizer, and further comprising an annulus formedbetween a wall of the conduit and a wall of the opening, wherein thesecond oxidizer is positionable in the annulus.
 5680. The system ofclaim 5679, wherein the first oxidizer is configurable to provide heatin the conduit, and wherein the second oxidizer is configurable toprovide heat outside of the conduit.
 5681. The system of claim 5679,wherein heat provided by the first oxidizer transfers in the firstconduit in a direction opposite of heat provided by the second oxidizer.5682. The system of claim 5679, wherein heat provided by the firstoxidizer transfers in the first conduit in a same direction as heatprovided by the second oxidizer.
 5683. The system of claim 5670, whereinthe oxidizer is configurable to oxidize fuel to generate heat, andfurther comprising a recycle conduit configurable to recycle at leastsome of the fuel in the conduit to a fuel source.
 5684. The system ofclaim 5670, wherein the oxidizer comprises a first oxidizer positionedin the conduit and a second oxidizer positioned in an annulus formedbetween a wall of the conduit and a wall of the opening, wherein theoxidizers are configurable to oxidize fuel to generate heat, and furthercomprising: a first recycle conduit configurable to recycle at leastsome of the fuel in the conduit to the second oxidizer; and a secondrecycle conduit configurable to recycle at least some of the fuel in theannulus to the first oxidizer.
 5685. The system of claim 5670, furthercomprising insulation positionable proximate the oxidizer.
 5686. An insitu method for heating a hydrocarbon containing formation, comprising:providing heat to a conduit positioned in an opening in the formation,wherein a first end of the opening contacts an earth surface at a firstlocation, and wherein a second end of the opening contacts the earthsurface at a second location; and allowing the heat in the conduit totransfer through the opening and to a surrounding portion of theformation.
 5687. The method of claim 5686, further comprising: providingfuel to an oxidizer; oxidizing at least some of the fuel; and allowingoxidation products to migrate through the opening, wherein the oxidationproducts comprise heat.
 5688. The method of claim 5687, wherein the fuelis provided to the oxidizer proximate the first location, and whereinthe oxidation products migrate towards the second location.
 5689. Themethod of claim 5686, wherein the oxidizer comprises a ring burner.5690. The method of claim 5686, wherein the oxidizer comprises an inlineburner.
 5691. The method of claim 5686, further comprising recycling atleast some fuel in the conduit.
 5692. A system configurable to provideheat to a hydrocarbon containing formation, comprising: a conduitpositionable in an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, wherein a secondend of the opening contacts the earth surface at a second location; anannulus formed between a wall of the conduit and a wall of the opening;and a oxidizer configurable to provide heat to a selected section of theformation by transferring heat through the annulus.
 5693. The system ofclaim 5692, wherein heat from the oxidizer pyrolyzes at least somehydrocarbons in the selected section.
 5694. The system of claim 5692,wherein the conduit is positioned in the opening.
 5695. The system ofclaim 5692, wherein the oxidizer comprises a first oxidizer and a secondoxidizer, wherein the second oxidizer is positioned in the conduit, andwherein the second oxidizer is configured to heat the selected section.5696. The system of claim 5692, wherein the oxidizer comprises a ringburner.
 5697. The system of claim 5692, wherein the oxidizer comprisesan inline burner.
 5698. The system of claim 5695, wherein heat providedby the first oxidizer transfers in the first conduit in a directionopposite of heat provided by the second oxidizer.
 5699. The system ofclaim 5692, wherein the oxidizer is configurable to oxidize fuel togenerate heat, and further comprising a recycle conduit configurable torecycle at least some of the fuel in the conduit to a fuel source. 5700.The system of claim 5692, further comprising insulation positionableproximate the oxidizer.
 5701. The system of claim 5692, wherein theconduit is positioned in the opening.
 5702. The system of claim 5692,wherein the oxidizer is positioned in the annulus, and wherein theoxidizer is configured to heat the selected section.
 5703. The system ofclaim 5692, wherein the oxidizer comprises a first oxidizer and a secondoxidizer.
 5704. The system of claim 5703, wherein heat provided by thefirst oxidizer transfers through the opening in a direction opposite ofheat provided by the second oxidizer.
 5705. The system of claim 5692,wherein the oxidizer is configurable to oxidize fuel to generate heat,and further comprising a recycle conduit configurable to recycle atleast some of the fuel in the annulus to a fuel source.
 5706. The systemof claim 5692, further comprising insulation positionable proximate theoxidizer.
 5707. The system of claim 5703, wherein the first oxidizer andthe second oxidizer comprise oxidizers, and wherein a first mixture ofoxidation products generated by the first oxidizer flows countercurrentto a second mixture of oxidation products generated by the secondheater.
 5708. The system of claim 5703, wherein the first heater and thesecond heater comprise oxidizers, wherein fuel is oxidized by theoxidizers to generate heat, and further comprising a first recycleconduit to recycle fuel in the first conduit proximate the secondlocation to the second conduit.
 5709. The system of claim 5703, whereinthe first oxidizer and the second oxidizer comprise oxidizers, whereinfuel is oxidized by the oxidizers to generate heat, and furthercomprising a second recycle conduit to recycle fuel in the secondconduit proximate the first location to the first conduit.
 5710. Thesystem of claim 5692, further comprising a casing, wherein the conduitis positionable in the casing.
 5711. The system of claim 5692, whereinthe oxidizer comprises a first oxidizer positioned in the annulus and asecond oxidizer positioned in the conduit, wherein the oxidizers areconfigurable to oxidize fuel to generate heat, and further comprising: afirst recycle conduit configurable to recycle at least some of the fuelin the annulus to the second oxidizer; and a second recycle conduitconfigurable to recycle at least some of the fuel in the conduit to thefirst oxidizer.
 5712. An in situ method for heating a hydrocarboncontaining formation, comprising: providing heat to an annulus formedbetween a wall of an opening in the formation and a wall of a conduit inthe opening, wherein a first end of the opening contacts an earthsurface at a first location, and wherein a second end of the openingcontacts the earth surface at a second location; and allowing the heatin the annulus to transfer through the opening and to a surroundingportion of the formation.
 5713. The method of claim 5712, furthercomprising: providing fuel to an oxidizer; oxidizing at least some ofthe fuel; and allowing oxidation products to migrate through theopening, wherein the oxidation products comprise heat.
 5714. The methodof claim 5713, wherein the fuel is provided the oxidizer proximate thefirst location, and wherein the oxidation products migrate towards thesecond location.
 5715. The method of claim 5712, wherein the oxidizercomprises a ring burner.
 5716. The method of claim 5712, wherein theoxidizer comprises an inline burner.
 5717. The method of claim 5712,further comprising recycling at least some fuel in the conduit.
 5718. Asystem configurable to provide heat to a hydrocarbon containingformation, comprising: a first conduit positionable in an opening in theformation, wherein a first end of the opening contacts an earth surfaceat a first location, wherein a second end of the opening contacts theearth surface at a second location; a second conduit positionable in theopening; a first oxidizer configurable to provide heat to a selectedsection of the formation by transferring heat through the first conduit;and a second oxidizer configurable to provide heat to the selectedsection of the formation by transferring heat through the secondconduit.
 5719. The system of claim 5718, wherein the first oxidizer ispositionable in the first conduit.
 5720. The system of claim 5718,wherein the second oxidizer is positionable in the second conduit. 5721.The system of claim 5718, further comprising a casing positionable inthe opening.
 5722. The system of claim 5718, wherein at least a portionof the second conduit is positionable in the first conduit, and furthercomprising an annulus formed between a wall of the first conduit and awall of the second conduit.
 5723. The system of claim 5718, wherein aportion of the second conduit is positionable proximate a portion of thefirst conduit.
 5724. The system of claim 5718, wherein the firstoxidizer or the second oxidizer provide heat to at least a portion ofthe formation.
 5725. The system of claim 5718, wherein the firstoxidizer and the second oxidizer provide heat to at least a portion ofthe formation concurrently.
 5726. The system of claim 5718, wherein thefirst oxidizer is positioned in the first conduit, wherein the secondoxidizer is positioned in the second conduit, wherein the first oxidizerand the second oxidizer comprise oxidizers, and wherein a first flow ofoxidation products from the first oxidizer flows in a direction oppositeof a second flow of oxidation products from the second oxidizer. 5727.The system of claim 5718, further comprising: a first recycle conduitconfigurable to recycle at least some of the fuel in the first conduitto the second oxidizer; and a second recycle conduit configurable torecycle at least some of the fuel in the second conduit to the firstoxidizer.
 5728. An in situ method for heating a hydrocarbon containingformation, comprising: providing heat to a first conduit positioned inan opening in the formation, wherein a first end of the opening contactsan earth surface at a first location, and wherein a second end of theopening contacts the earth surface at a second location; providing heatto a second conduit positioned in the opening in the formation; allowingthe heat in the first conduit to transfer through the opening and to asurrounding portion of the formation; and allowing the heat in thesecond conduit to transfer through the opening and to a surroundingportion of the formation;
 5729. The method of claim 5728, whereinproviding heat to the first conduit comprises providing fuel to anoxidizer.
 5730. The method of claim 5728, wherein providing heat to thesecond conduit comprises providing fuel to an oxidizer.
 5731. The methodof claim 5728, wherein the first fuel is provided to the first conduitproximate the first location, and wherein the second fuel is provided tothe second conduit proximate the second location.
 5732. The method ofclaim 5728, wherein the first oxidizer or the second oxidizer comprisesa ring burner.
 5733. The method of claim 5728, wherein the firstoxidizer or the second oxidizer an inline burner.
 5734. The method ofclaim 5728, further comprising: transferring heat through the firstconduit in a first direction; and transferring heat in the secondconduit in a second direction.
 5735. The method of claim 5728, furthercomprising recycling at least some fuel in the first conduit to thesecond conduit; and recycling at least some fuel in the second conduitto the first conduit.
 5736. A system configurable to provide heat to ahydrocarbon containing formation, comprising: a first conduitpositionable in an opening in the formation, wherein a first end of theopening contacts an earth surface at a first location, wherein a secondend of the opening contacts the earth surface at a second location; asecond conduit positionable in the first conduit; and at least onesurface unit configurable to provide heat to the first conduit. 5737.The system of claim 5736, wherein the surface unit comprises a furnace.5738. The system of claim 5736, wherein the surface unit comprises aburner.
 5739. The system of claim 5736, wherein at least one surfaceunit is configurable to provide heat to the second conduit.
 5740. Thesystem of claim 5739, wherein the first conduit and the second conduitprovide heat to at least a portion of the formation.
 5741. The system ofclaim 5739, wherein the first conduit provides heat to at least aportion of the formation.
 5742. The system of claim 5739, wherein thesecond conduit provides heat to at least a portion of the formation.5743. The system of claim 5736, further comprising a casing positionablein the opening.
 5744. The system of claim 5736, wherein the firstconduit and the second conduit are concentric.
 5745. An in situ methodfor heating a hydrocarbon containing formation, comprising: heating afluid using at least one surface unit; providing the heated fluid to afirst conduit wherein a portion of the first conduit is positioned in anopening in the formation, wherein a first end of the opening contacts anearth surface at a first location, and wherein a second end of theopening contacts the earth surface at a second location; allowing theheated fluid to flow into a second conduit, wherein the first conduit ispositioned within the second conduit; and allowing heat from the firstand second conduit to transfer to a portion of the formation.
 5746. Themethod of claim 5745, further comprising providing additional heat tothe heated fluid using at least one surface unit proximate the secondlocation.
 5747. The method of claim 5745, wherein the fluid comprises anoxidizing fluid.
 5748. The method of claim 5745, wherein the fluidcomprises air.
 5749. The method of claim 5745, wherein the fluidcomprises flue gas.
 5750. The method of claim 5745, wherein the fluidcomprises steam.
 5751. The method of claim 5745, wherein the fluidcomprises fuel.
 5752. The method of claim 5745, further comprisingcompressing the fluid prior to heating.
 5753. The method of claim 5745,wherein the surface unit comprises a furnace.
 5754. The method of claim5745, wherein the surface unit comprises an indirect furnace.
 5755. Themethod of claim 5745, wherein the surface unit comprises a burner. 5756.The method of claim 5745, wherein the first conduit and the secondconduit are concentric.
 5757. A system configurable to provide heat to ahydrocarbon containing formation, comprising: a conduit positionable inat least a portion of an opening in the formation, wherein a first endof the opening contacts an earth surface at a first location, andwherein a second end of the opening contacts the earth surface at asecond location; and at least two oxidizers configurable to provide heatto a portion of the formation.
 5758. The system of claim 5757, whereinheat from the oxidizers pyrolyzes at least some hydrocarbons in theselected section.
 5759. The system of claim 5757, wherein the conduitcomprises a fuel conduit.
 5760. The system of claim 5757, wherein atleast one oxidizer is positionable proximate the conduit.
 5761. Thesystem of claim 5757, wherein at least one oxidizer comprises a ringburner.
 5762. The system of claim 5757, wherein at least one oxidizercomprises an inline burner.
 5763. The system of claim 5757, furthercomprising insulation positionable proximate at least one oxidizer.5764. The system of claim 5757, further comprising a casing comprisinginsulation proximate at least one oxidizer.
 5765. An in situ method forheating a hydrocarbon containing formation, comprising: providing fuelto a conduit positioned in an opening in the formation, wherein a firstend of the opening contacts an earth surface at a first location, andwherein a second end of the opening contacts the earth surface at asecond location; providing an oxidizing fluid to the opening; oxidizingfuel in at least one oxidizer positioned proximate the conduit; andallowing heat to transfer to a portion of the formation.
 5766. Themethod of claim 5765, further comprising providing steam to the conduit.5767. The method of claim 5765, further comprising inhibiting cokingwithin the conduit.
 5768. The method of claim 5765, wherein theoxidizing fluid comprises air.
 5769. The method of claim 5765, whereinthe oxidizing fluid comprises oxygen.
 5770. The method of claim 5765,further comprising allowing oxidation products to exit the openingproximate the second location.
 5771. The method of claim 5765, whereinthe fuel is provided to proximate the first location, and wherein theoxidation products migrate towards the second location.
 5772. The methodof claim 5765, wherein the oxidizer comprises a ring burner.
 5773. Themethod of claim 5765, wherein the oxidizer comprises an inline burner.5774. The method of claim 5765, further comprising recycling at leastsome fuel in the conduit.
 5775. The system of claim 5765, wherein theopening comprises a casing and further comprising insulating a portionof the casing proximate at least one oxidizer.
 5776. The system of claim5765, further comprising at least two oxidizers, wherein the oxidizersare positioned about 30 m apart.
 5777. A system configurable to provideheat to a hydrocarbon containing formation, comprising: a conduitpositionable in at least a portion of an opening in the formation,wherein a first end of the opening contacts an earth surface at a firstlocation, and wherein a second end of the opening contacts the earthsurface at a second location; and an oxidizing fluid source configurableto provide an oxidizing fluid to a reaction zone of the formation. 5778.The system of claim 5777, wherein the conduit comprises a conductor andwherein the conductor is configured to generate heat during applicationof an electrical current to the conduit.
 5779. The system of claim 5777,wherein the conduit comprises a low resistance conductor and wherein atleast some of the low resistance conductor is positionable in anoverburden.
 5780. The system of claim 5777, wherein the oxidizing fluidsource is configurable to provide at least some oxidizing fluid to theconduit at the first location and at the second location.
 5781. Thesystem of claim 5777, wherein the opening is configurable to allowproducts of oxidation to be produced from the formation.
 5782. Thesystem of claim 5777, wherein the oxidizing fluid reacts with at leastsome hydrocarbons and wherein the oxidizing fluid source is configurableto provide at least some oxidizing fluid to the first location and tothe second location.
 5783. The system of claim 5777, wherein the heateris configurable to heat a reaction zone of the selected section to atemperature sufficient to support reaction of hydrocarbons in theselected section with an oxidizing fluid.
 5784. The system of claim5783, wherein the heater is configurable to provide an oxidizing fluidto the selected section of the formation to generate heat during use.5785. The system of claim 5783, wherein the generated heat transfers toa pyrolysis zone of the formation.
 5786. The system of claim 5777,further comprising an oxidizing fluid source configurable to provide anoxidizing fluid to the heater, and wherein the conduit is configurableto provide the oxidizing fluid to the selected section of the formationduring use.
 5787. The system of claim 5777, wherein the conduitcomprises a low resistance conductor and a conductor, and wherein theconductor is further configured to generate heat during application ofan electrical current to the conduit.
 5788. An in situ method forheating a hydrocarbon containing formation, comprising: providing anelectrical current to a conduit positioned in an opening in theformation; allowing heat to transfer from the conduit to a reaction zoneof the formation; providing at least some oxidizing fluid to theconduit; allowing the oxidizing fluid to transfer from the conduit tothe reaction zone in the formation; allowing the oxidizing fluid tooxidize at least some hydrocarbons in the reaction zone to generateheat; and allowing at least some of the generated heat to transfer to apyrolysis zone in the formation.
 5789. The method of claim 5788, whereinat least a portion of the conduit is configured to generate heat duringapplication of the electrical current to the conduit.
 5790. The methodof claim 5788, further comprising: providing at least some oxidizingfluid to the conduit proximate a first end of the conduit; providing atleast some oxidizing fluid to the conduit proximate a second end of theconduit; and wherein the first end of the conduit is positioned at afirst location on a surface of the formation and wherein the second endof the conduit is positioned at a second location on the surface. 5791.The method of claim 5788, further comprising allowing the oxidizingfluid to move out of the conduit through orifices positioned on theconduit.
 5792. The method of claim 5788, further comprising removingproducts of oxidation through the opening during use.
 5793. The methodof claim 5788, wherein a first end of the opening is positioned at afirst location on a surface of the formation and wherein a second end ofthe opening is positioned at a second location on the surface.
 5794. Themethod of claim 5788, further comprising heating the reaction zone to atemperature sufficient to support reaction of hydrocarbons with anoxidizing fluid.
 5795. The method of claim 5788, further comprisingcontrolling a flow rate of the oxidizing fluid into the formation. 5796.The method of claim 5788, further comprising controlling a temperaturein the pyrolysis zone.
 5797. The method of claim 5788, furthercomprising removing products from oxidation through an opening in theformation during use.
 5798. A method for treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from the one or more heaters to a first section of theformation such that the heat from the one or more heaters pyrolyzes atleast some hydrocarbons within the first section; and producing amixture through a second section of the formation, wherein the producedmixture comprises at least some pyrolyzed hydrocarbons from the firstsection, and wherein the second section comprises a higher permeabilitythan the first section.
 5799. The method of claim 5798, wherein the heatprovided from at least one heater is transferred to the formationsubstantially by conduction.
 5800. The method of claim 5798, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 5801. The method of claim 5798, further comprising increasingpermeability within the second section by allowing heat to transfer fromthe one or more heaters to the second section.
 5802. The method of claim5798, wherein the second section has a higher permeability than thefirst section before providing heat to the formation.
 5803. The methodof claim 5798, wherein the second section comprises an averagepermeability thickness product of greater than about 100 millidarcyfeet.
 5804. The method of claim 5798, wherein the first sectioncomprises an initial average permeability thickness product of less thanabout 10 millidarcy feet.
 5805. The method of claim 5798, wherein thesecond section comprises an average permeability thickness product thatis at least twice an initial average permeability thickness product ofthe first section.
 5806. The method of claim 5798, wherein the secondsection comprises an average permeability thickness product that is atleast ten times an initial average permeability thickness product of thefirst section.
 5807. The method of claim 5798, wherein the one or moreheaters are placed within at least one uncased wellbore in theformation.
 5808. The method of claim 5807, further comprising allowingat least some hydrocarbons from the first section to propagate throughat least one uncased wellbore into the second section.
 5809. The methodof claim 5807, further comprising producing at least some hydrocarbonsthrough at least one uncased wellbore.
 5810. The method of claim 5798,further comprising forming one or more fractures that propagate betweenthe first section and the second section.
 5811. The method of claim5810, further comprising allowing at least some hydrocarbons from thefirst section to propagate through the one or more fractures into thesecond section.
 5812. The method of claim 5798, further comprisingproducing the mixture from the formation through a production wellplaced in the second section.
 5813. The method of claim 5798, furthercomprising producing the mixture from the formation through a productionwell placed in the first section and the second section.
 5814. Themethod of claim 5798, further comprising inhibiting fracturing of asection of the formation that is substantially adjacent to anenvironmentally sensitive area.
 5815. The method of claim 5798, furthercomprising producing at least some hydrocarbons through the secondsection to maintain a pressure in the formation below a lithostaticpressure of the formation.
 5816. The method of claim 5798, furthercomprising producing at least some hydrocarbons through a productionwell placed in the first section.
 5817. The method of claim 5798,further comprising pyrolyzing at least some hydrocarbons within thesecond section.
 5818. The method of claim 5798, wherein the firstsection and the second section are substantially adjacent.
 5819. Themethod of claim 5798, further comprising allowing migration of fluidsbetween the first second and the second section.
 5820. The method ofclaim 5798, wherein at least one heater has a thickness of a conductorthat is adjusted to provide more heat to the first section than thesecond section.
 5821. A method for treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation, wherein one or more of suchheaters is placed within at least one uncased wellbore in the formation;allowing the heat to transfer from the one or more heaters to a firstsection of the formation such that the heat from the one or more heaterspyrolyzes at least some hydrocarbons within the first section; andproducing a mixture through a second section of the formation, whereinthe produced mixture comprises at least some pyrolyzed hydrocarbons fromthe first section, and wherein the second section comprises a higherpermeability than the first section.
 5822. The method of claim 5821,further comprising allowing at least some hydrocarbons from the firstsection to propagate through at least one uncased wellbore into thesecond section.
 5823. The method of claim 5821, further comprisingproducing at least some hydrocarbons through at least one uncasedwellbore.
 5824. A method of using a computer system for modeling an insitu process for treating a hydrocarbon containing formation,comprising: providing at least one property of the formation to thecomputer system; providing at least one operating condition of theprocess to the computer system, wherein the in situ process comprisesproviding heat from one or more heaters to at least one portion of theformation, and wherein the in situ process comprises allowing the heatto transfer from the one or more heaters to a selected section of theformation; and assessing at least one process characteristic of the insitu process using a simulation method on the computer system, and usingat least one property of the formation and at least one operatingcondition.
 5825. The method of claim 5824, wherein at least one processcharacteristic is assessed as function of time.
 5826. The method ofclaim 5824, wherein the simulation method is a body-fitted finitedifference simulation method.
 5827. The method of claim 5824, whereinthe simulation method is a space-fitted finite difference simulationmethod.
 5828. The method of claim 5824, wherein the simulation method isa reservoir simulation method.
 5829. The method of claim 5824, whereinthe simulation method simulates heat transfer by conduction.
 5830. Themethod of claim 5824, wherein the simulation method simulates heattransfer by convection.
 5831. The method of claim 5824, wherein thesimulation method simulates heat transfer by radiation.
 5832. The methodof claim 5824, wherein the simulation method simulates heat transfer ina near wellbore region.
 5833. The method of claim 5824, wherein thesimulation method assesses a temperature distribution in the formation.5834. The method of claim 5824, wherein at least one property of theformation comprises one or more materials from the formation.
 5835. Themethod of claim 5834, wherein one material comprises mineral matter.5836. The method of claim 5834, wherein one material comprises organicmatter.
 5837. The method of claim 5824, wherein at least one property ofthe formation comprises one or more phases.
 5838. The method of claim5837, wherein one phase comprises a water phase.
 5839. The method ofclaim 5837, wherein one phase comprises an oil phase.
 5840. The methodof claim 5839, wherein the oil phase comprises one or more components.5841. The method of claim 5837, wherein one phase comprises a gas phase.5842. The method of claim 5841, wherein the gas phase comprises one ormore components.
 5843. The method of claim 5824, wherein at least oneproperty of the formation comprises a porosity of the formation. 5844.The method of claim 5824, wherein at least one property of the formationcomprises a permeability of the formation.
 5845. The method of claim5844, wherein the permeability depends on the composition of theformation.
 5846. The method of claim 5824, wherein at least one propertyof the formation comprises a saturation of the formation.
 5847. Themethod of claim 5824, wherein at least one property of the formationcomprises a density of the formation.
 5848. The method of claim 5824,wherein at least one property of the formation comprises a thermalconductivity of the formation.
 5849. The method of claim 5824, whereinat least one property of the formation comprises a volumetric heatcapacity of the formation.
 5850. The method of claim 5824, wherein atleast one property of the formation comprises a compressibility of theformation.
 5851. The method of claim 5824, wherein at least one propertyof the formation comprises a composition of the formation.
 5852. Themethod of claim 5824, wherein at least one property of the formationcomprises a thickness of the formation.
 5853. The method of claim 5824,wherein at least one property of the formation comprises a depth of theformation.
 5854. The method of claim 5824, wherein at least one propertycomprises one or more chemical components.
 5855. The method of claim5854, wherein one component comprises a pseudo-component.
 5856. Themethod of claim 5824, wherein at least property comprises one or morekinetic parameters.
 5857. The method of claim 5824, wherein at least oneproperty comprises one or more chemical reactions.
 5858. The method ofclaim 5857, wherein a rate of at least one chemical reaction depends ona pressure of the formation.
 5859. The method of claim 5857, wherein arate of at least one chemical reaction depends on a temperature of theformation.
 5860. The method of claim 5857, wherein at least one chemicalreaction comprises a pre-pyrolysis water generation reaction.
 5861. Themethod of claim 5857, wherein at least one chemical reaction comprises ahydrocarbon generating reaction.
 5862. The method of claim 5857, whereinat least one chemical reaction comprises a coking reaction.
 5863. Themethod of claim 5857, wherein at least one chemical reaction comprise acracking reaction.
 5864. The method of claim 5857, wherein at least onechemical reaction comprises a synthesis gas reaction.
 5865. The methodof claim 5824, wherein at least one process characteristic comprises anAPI gravity of produced fluids.
 5866. The method of claim 5824, whereinat least one process characteristic comprises an olefin content ofproduced fluids.
 5867. The method of claim 5824, wherein at least oneprocess characteristic comprises a carbon number distribution ofproduced fluids.
 5868. The method of claim 5824, wherein at least oneprocess characteristic comprises an ethene to ethane ratio of producedfluids.
 5869. The method of claim 5824, wherein at least one processcharacteristic comprises an atomic carbon to hydrogen ratio of producedfluids.
 5870. The method of claim 5824, wherein at least one processcharacteristic comprises a ratio of non-condensable hydrocarbons tocondensable hydrocarbons of produced fluids.
 5871. The method of claim5824, wherein at least one process characteristic comprises a pressurein the formation.
 5872. The method of claim 5824, wherein at least oneprocess characteristic comprises total mass recovery from the formation.5873. The method of claim 5824, wherein at least one processcharacteristic comprises a production rate of fluid produced from theformation.
 5874. The method of claim 5824, wherein at least oneoperating condition comprises a pressure.
 5875. The method of claim5824, wherein at least one operating condition comprises a temperature.5876. The method of claim 5824, wherein at least one operating conditioncomprises a heating rate.
 5877. The method of claim 5824, wherein atleast one operating condition comprises a process time.
 5878. The methodof claim 5824, wherein at least one operating condition comprises alocation of producer wells.
 5879. The method of claim 5824, wherein atleast one operating condition comprises an orientation of producerwells.
 5880. The method of claim 5824, wherein at least one operatingcondition comprises a ratio of producer wells to heater wells.
 5881. Themethod of claim 5824, wherein at least one operating condition comprisesa spacing between heater wells.
 5882. The method of claim 5824, whereinat least one operating condition comprises a distance between anoverburden and horizontal heater wells.
 5883. The method of claim 5824,wherein at least one operating condition comprises a pattern of heaterwells.
 5884. The method of claim 5824, wherein at least one operatingcondition comprises an orientation of heater wells.
 5885. A method ofusing a computer system for modeling an in situ process for treating ahydrocarbon containing formation, comprising: simulating a heat inputrate to the formation from two or more heaters on the computer system,wherein heat is allowed to transfer from the heaters to a selectedsection of the formation; providing at least one desired parameter ofthe in situ process to the computer system; and controlling the heatinput rate from the heaters to achieve at least one desired parameter.5886. The method of claim 5885, wherein the heat is allowed to transferfrom the heaters substantially by conduction.
 5887. The method of claim5885, wherein the heat input rate is simulated with a body-fitted finitedifference simulation method.
 5888. The method of claim 5885, whereinsimulating the heat input rate from two or more heaters comprisessimulating a model of one or more heaters with symmetry boundaryconditions.
 5889. The method of claim 5885, wherein superposition ofheat from the two or more heaters pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 5890. The method of claim5885, wherein at least one desired parameter comprises a selectedprocess characteristic.
 5891. The method of claim 5885, wherein at leastone desired parameter comprises a selected temperature.
 5892. The methodof claim 5885, wherein at least one desired parameter comprises aselected heating rate.
 5893. The method of claim 5885, wherein at leastone desired parameter comprises a desired product mixture produced fromthe formation.
 5894. The method of claim 5885, wherein at least onedesired parameter comprises a desired product mixture produced from theformation, and wherein the desired product mixture comprises a selectedcomposition.
 5895. The method of claim 5885, wherein at least onedesired parameter comprises a selected pressure.
 5896. The method ofclaim 5885, wherein at least one desired parameter comprises a selectedheating time.
 5897. The method of claim 5885, wherein at least onedesired parameter comprises a market parameter.
 5898. The method ofclaim 5885, wherein at least one desired parameter comprises a price ofcrude oil.
 5899. The method of claim 5885, wherein at least one desiredparameter comprises an energy cost.
 5900. The method of claim 5885,wherein at least one desired parameter comprises a selected molecularhydrogen to carbon monoxide volume ratio.
 5901. A method of using acomputer system for modeling an in situ process for treating ahydrocarbon containing formation, comprising: providing at least oneheat input property to the computer system; assessing heat injectionrate data for the formation using a first simulation method on thecomputer system; providing at least one property of the formation to thecomputer system; assessing at least one process characteristic of the insitu process from the heat injection rate data and at least one propertyof the formation using a second simulation method; and wherein the insitu process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation.
 5902. The method of claim 5901,wherein at least one process characteristic is assessed as a function oftime.
 5903. The method of claim 5901, wherein assessing heat injectionrate data comprises simulating heating of the formation.
 5904. Themethod of claim 5901, wherein the heating is controlled to obtain adesired parameter.
 5905. The method of claim 5901, wherein determiningat least one process characteristic comprises simulating heating of theformation.
 5906. The method of claim 5905, wherein the heating iscontrolled to obtain a desired parameter.
 5907. The method of claim5901, wherein the first simulation method is a body-fitted finitedifference simulation method.
 5908. The method of claim 5901, whereinthe second simulation method is a space-fitted finite differencesimulation method.
 5909. The method of claim 5901, wherein the secondsimulation method is a reservoir simulation method.
 5910. The method ofclaim 5901, wherein the first simulation method simulates heat transferby conduction.
 5911. The method of claim 5901, wherein the firstsimulation method simulates heat transfer by convection.
 5912. Themethod of claim 5901, wherein the first simulation method simulates heattransfer by radiation.
 5913. The method of claim 5901, wherein thesecond simulation method simulates heat transfer by conduction. 5914.The method of claim 5901, wherein the second simulation method simulatesheat transfer by convection.
 5915. The method of claim 5901, wherein thefirst simulation method simulates heat transfer in a near wellboreregion.
 5916. The method of claim 5901, wherein the first simulationmethod determines a temperature distribution in the formation.
 5917. Themethod of claim 5901, wherein at least one heat input property comprisesa property of the formation.
 5918. The method of claim 5901, wherein atleast one heat input property comprises a heat transfer property. 5919.The method of claim 5901, wherein at least one heat input propertycomprises an initial property of the formation.
 5920. The method ofclaim 5901, wherein at least one heat input property comprises a heatcapacity.
 5921. The method of claim 5901, wherein at least one heatinput property comprises a thermal conductivity.
 5922. The method ofclaim 5901, wherein the heat injection rate data comprises a temperaturedistribution within the formation.
 5923. The method of claim 5901,wherein the heat injection rate data comprises a heat input rate. 5924.The method of claim 5923, wherein the heat input rate is controlled tomaintain a specified maximum temperature at a point in the formation.5925. The method of claim 5901, wherein the heat injection rate datacomprises heat flux data.
 5926. The method of claim 5901, wherein atleast one property of the formation comprises one or more materials inthe formation.
 5927. The method of claim 5926, wherein one materialcomprises mineral matter.
 5928. The method of claim 5926, wherein onematerial comprises organic matter.
 5929. The method of claim 5901,wherein at least one property of the formation comprises one or morephases.
 5930. The method of claim 5929, wherein one phase comprises awater phase.
 5931. The method of claim 5929, wherein one phase comprisesan oil phase.
 5932. The method of claim 5931, wherein the oil phasecomprises one or more components.
 5933. The method of claim 5929,wherein one phase comprises a gas phase.
 5934. The method of claim 5933,wherein the gas phase comprises one or more components.
 5935. The methodof claim 5901, wherein at least one property of the formation comprisesa porosity of the formation.
 5936. The method of claim 5901, wherein atleast one property of the formation comprises a permeability of theformation.
 5937. The method of claim 5936, wherein the permeabilitydepends on the composition of the formation.
 5938. The method of claim5901, wherein at least one property of the formation comprises asaturation of the formation.
 5939. The method of claim 5901, wherein atleast one property of the formation comprises a density of theformation.
 5940. The method of claim 5901, wherein at least one propertyof the formation comprises a thermal conductivity of the formation.5941. The method of claim 5901, wherein at least one property of theformation comprises a volumetric heat capacity of the formation. 5942.The method of claim 5901, wherein at least one property of the formationcomprises a compressibility of the formation.
 5943. The method of claim5901, wherein at least one property of the formation comprises acomposition of the formation.
 5944. The method of claim 5901, wherein atleast one property of the formation comprises a thickness of theformation.
 5945. The method of claim 5901, wherein at least one propertyof the formation comprises a depth of the formation.
 5946. The method ofclaim 5901, wherein at least one property of the formation comprises oneor more chemical components.
 5947. The method of claim 5946, wherein atleast one chemical component comprises a pseudo-component.
 5948. Themethod of claim 5901, wherein at least one property of the formationcomprises one or more kinetic parameters.
 5949. The method of claim5901, wherein at least one property of the formation comprises one ormore chemical reactions.
 5950. The method of claim 5949, wherein a rateof at least one chemical reaction depends on a pressure of theformation.
 5951. The method of claim 5949, wherein a rate of at leastone chemical reaction depends on a temperature of the formation. 5952.The method of claim 5949, wherein at least one chemical reactioncomprises a pre-pyrolysis water generation reaction.
 5953. The method ofclaim 5949, wherein at least one chemical reaction comprises ahydrocarbon generating reaction.
 5954. The method of claim 5949, whereinat least one chemical reaction comprises a coking reaction.
 5955. Themethod of claim 5949, wherein at least one chemical reaction comprises acracking reaction.
 5956. The method of claim 5949, wherein at least onechemical reaction comprises a synthesis gas reaction.
 5957. The methodof claim 5901, wherein at least one process characteristic comprises anAPI gravity of produced fluids.
 5958. The method of claim 5901, whereinat least one process characteristic comprises an olefin content ofproduced fluids.
 5959. The method of claim 5901, wherein at least oneprocess characteristic comprises a carbon number distribution ofproduced fluids.
 5960. The method of claim 5901, wherein at least oneprocess characteristic comprises an ethene to ethane ratio of producedfluids.
 5961. The method of claim 5901, wherein at least one processcharacteristic comprises an atomic carbon to hydrogen ratio of producedfluids.
 5962. The method of claim 5901, wherein at least one processcharacteristic comprises a ratio of non-condensable hydrocarbons tocondensable hydrocarbons of produced fluids.
 5963. The method of claim5901, wherein at least one process characteristic comprises a pressurein the formation.
 5964. The method of claim 5901, wherein at least oneprocess characteristic comprises a total mass recovery from theformation.
 5965. The method of claim 5901, wherein at least one processcharacteristic comprises a production rate of fluid produced from theformation.
 5966. The method of claim 5901, further comprising: assessingmodified heat injection rate data using the first simulation method at aspecified time of the second simulation method based on at least oneheat input property of the formation at the specified time; assessing atleast one process characteristic of the in situ process as a function oftime from the modified heat injection rate data and at least oneproperty of the formation at the specified time using the secondsimulation method.
 5967. A method of using a computer system formodeling an in situ process for treating a hydrocarbon containingformation, comprising: providing one or more model parameters for the insitu process to the computer system; assessing one or more simulatedprocess characteristics based on one or more model parameters using asimulation method; modifying one or more model parameters such that atleast one simulated process characteristic matches or approximates atleast one real process characteristic; assessing one or more modifiedsimulated process characteristics based on the modified modelparameters; and wherein the in situ process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation. 5968.The method of claim 5967, further comprising using the simulation methodwith the modified model parameters to determine at least one operatingcondition of the in situ process to achieve a desired parameter. 5969.The method of claim 5967, wherein the simulation method comprises abody-fitted finite difference simulation method.
 5970. The method ofclaim 5967, wherein the simulation method comprises a space-fittedfinite difference simulation method.
 5971. The method of claim 5967,wherein the simulation method comprises a reservoir simulation method.5972. The method of claim 5967, wherein the real process characteristicscomprise process characteristics obtained from laboratory experiments ofthe in situ process.
 5973. The method of claim 5967, wherein the realprocess characteristics comprise process characteristics obtained fromfield test experiments of the in situ process.
 5974. The method of claim5967, further comprising comparing the simulated process characteristicsto the real process characteristics as a function of time.
 5975. Themethod of claim 5967, further comprising associating differences betweenthe simulated process characteristics and the real processcharacteristics with one or more model parameters.
 5976. The method ofclaim 5967, wherein at least one model parameter comprises a chemicalcomponent.
 5977. The method of claim 5967, wherein at least one modelparameter comprises a kinetic parameter.
 5978. The method of claim 5977,wherein the kinetic parameter comprises an order of a reaction. 5979.The method of claim 5977, wherein the kinetic parameter comprises anactivation energy.
 5980. The method of claim 5977, wherein the kineticparameter comprises a reaction enthalpy.
 5981. The method of claim 5977,wherein the kinetic parameter comprises a frequency factor.
 5982. Themethod of claim 5967, wherein at least one model parameter comprises achemical reaction.
 5983. The method of claim 5982, wherein at least onechemical reaction comprises a pre-pyrolysis water generation reaction.5984. The method of claim 5982, wherein at least one chemical reactioncomprises a hydrocarbon generating reaction.
 5985. The method of claim5982, wherein at least one chemical reaction comprises a cokingreaction.
 5986. The method of claim 5982, wherein at least one chemicalreaction comprises a cracking reaction.
 5987. The method of claim 5982,wherein at least one chemical reaction comprises a synthesis gasreaction.
 5988. The method of claim 5967, wherein one or more modelparameters comprise one or more properties.
 5989. The method of claim5967, wherein at least one model parameter comprises a relationship forthe dependence of a property on a change in conditions in the formation.5990. The method of claim 5967, wherein at least one model parametercomprises an expression for the dependence of porosity on pressure inthe formation.
 5991. The method of claim 5967, wherein at least onemodel parameter comprises an expression for the dependence ofpermeability on porosity.
 5992. The method of claim 5967, wherein atleast one model parameter comprises an expression for the dependence ofthermal conductivity on composition of the formation.
 5993. A method ofusing a computer system for modeling an in situ process for treating ahydrocarbon containing formation, comprising: assessing at least oneoperating condition of the in situ process using a simulation methodbased on one or more model parameter; modifying at least one modelparameter such that at least one simulated process characteristic of thein situ process matches or approximates at least one real processcharacteristic of the in situ process; assessing one or more modifiedsimulated process characteristics based on the modified modelparameters; and wherein the in situ process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation. 5994.The method of claim 5993, wherein at least one operating condition isassessed to achieve at least one desired parameter.
 5995. The method ofclaim 5993, wherein the real process characteristic comprises a processcharacteristic from a field test of the in situ process.
 5996. Themethod of claim 5993, wherein the simulation method comprises abody-fitted finite difference simulation method.
 5997. The method ofclaim 5993, wherein the simulation method comprises a space-fittedfinite difference simulation method.
 5998. The method of claim 5993,wherein the simulation method comprises a reservoir simulation method.5999. A method of modeling a process of treating a hydrocarboncontaining formation in situ using a computer system, comprising:providing one or more model parameters to the computer system; assessingone or more first process characteristics based on the one or more modelparameters using a first simulation method on the computer system;assessing one or more second process characteristics based on one ormore model parameters using a second simulation method on the computersystem; modifying one or more model parameters such that at least onefirst process characteristic matches or approximates at least one secondprocess characteristic; and wherein the in situ process comprisesproviding heat from one or more heaters to at least one portion of theformation, and wherein the in situ process comprises allowing the heatto transfer from the one or more heaters to a selected section of theformation.
 6000. The method of claim 5999, further comprising assessingone or more third process characteristics based on the one or moremodified model parameters using the second simulation method.
 6001. Themethod of claim 5999, wherein modifying one or more model parameterssuch that at least one first process characteristic matches orapproximates at least one second process characteristic furthercomprises: assessing at least one set of first process characteristicsbased on at least one set of modified model parameters using the firstsimulation method; and assessing the set of modified model parametersthat results in at least one first process characteristic that matchesor approximates at least one second process characteristic.
 6002. Themethod of claim 5999, wherein the first simulation method comprises abody-fitted finite difference simulation method.
 6003. The method ofclaim 5999, wherein the second simulation method comprises aspace-fitted finite difference simulation method.
 6004. The method ofclaim 5999, wherein at least one first process characteristic comprisesa process characteristic at a sharp interface in the formation. 6005.The method of claim 5999, wherein at least one first processcharacteristic comprises a process characteristic at a combustion frontin the formation.
 6006. The method of claim 5999, wherein modifying theone or more model parameters comprises changing the order of a chemicalreaction.
 6007. The method of claim 5999, wherein modifying the one ormore model parameters comprises adding one or more chemical reactions.6008. The method of claim 5999, wherein modifying the one or more modelparameters comprises changing an activation energy.
 6009. The method ofclaim 5999, wherein modifying the one or more model parameters compriseschanging a frequency factor.
 6010. A method of using a computer systemfor modeling an in situ process for treating a hydrocarbon containingformation, comprising: providing to the computer system one or morevalues of at least one operating condition of the in situ process,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; assessing one ormore values of at least one process characteristic corresponding to oneor more values of at least one operating condition using a simulationmethod; providing a desired value of at least one process characteristicfor the in situ process to the computer system; and assessing a desiredvalue of at least one operating condition to achieve the desired valueof at least one process characteristic from the assessed values of atleast one process characteristic and the provided values of at least oneoperating condition.
 6011. The method of claim 6010, further comprisingoperating the in situ system using the desired value of at least oneoperating condition.
 6012. The method of claim 6010, wherein the processcomprises providing heat from one or more heaters to at least oneportion of the formation.
 6013. The method of claim 6010, wherein theprocess comprises allowing heat to transfer from one or more heaters toa selected section of the formation.
 6014. The method of claim 6010,wherein a value of at least one process characteristic comprises theprocess characteristic as a function of time.
 6015. The method of claim6010, further comprising determining a value of at least one processcharacteristic based on the desired value of at least one operatingcondition using the simulation method.
 6016. The method of claim 6010,wherein determining the desired value of at least one operatingcondition comprises interpolating the desired value from the determinedvalues of at least one process characteristic and the provided values ofat least one operating condition.
 6017. A method of using a computersystem for modeling an in situ process for treating a hydrocarboncontaining formation, comprising: providing a desired value of at leastone process characteristic for the in situ process to the computersystem, wherein the in situ process comprises providing heat from one ormore heaters to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; and assessing avalue of at least one operating condition to achieve the desired valueof at least one process characteristic, wherein such assessing comprisesusing a relationship between at least one process characteristic and atleast one operating condition for the in situ process, wherein suchrelationship is stored on a database accessible by the computer system.6018. The method of claim 6017, further comprising operating the in situsystem using the desired value of at least one operating condition.6019. The method of claim 6017, wherein the process comprises providingheat from one or more heaters to at least one portion of the formation.6020. The method of claim 6017, wherein the process comprises providingheat to transfer from one or more heaters to a selected section of theformation.
 6021. The method of claim 6017, wherein the relationship isdetermined from one or more simulations of the in situ process using asimulation method.
 6022. The method of claim 6017, wherein therelationship comprises one or more values of at least one processcharacteristic and corresponding values of at least one operatingcondition.
 6023. The method of claim 6017, wherein the relationshipcomprises an analytical function.
 6024. The method of claim 6017,wherein determining the value of at least one operating conditioncomprises interpolating the value of at least one operating conditionfrom the relationship.
 6025. The method of claim 6017, wherein at leastone process characteristic comprises a selected composition of producedfluids.
 6026. The method of claim 6017, wherein at least one operatingcondition comprises a pressure.
 6027. The method of claim 6017, whereinat least one operating condition comprises a heat input rate.
 6028. Asystem, comprising: a CPU; a data memory coupled to the CPU; and asystem memory coupled to the CPU, wherein the system memory isconfigured to store one or more computer programs executable by the CPU,and wherein the computer programs are executable to implement a methodof using a computer system for modeling an in situ process for treatinga hydrocarbon containing formation, the method comprising: providing atleast one property of the formation to the computer system; providing atleast one operating condition of the process to the computer system,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; and assessing atleast one process characteristic of the in situ process using asimulation method on the computer system, and using at least oneproperty of the formation and at least one operating condition.
 6029. Acarrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:providing at least one property of the formation to the computer system;providing at least one operating condition of the process to thecomputer system, wherein the in situ process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation; andassessing at least one process characteristic of the in situ processusing a simulation method on the computer system, and using at least oneproperty of the formation and at least one operating condition.
 6030. Asystem, comprising: a CPU; a data memory coupled to the CPU; and asystem memory coupled to the CPU, wherein the system memory isconfigured to store one or more computer programs executable by the CPU,and wherein the computer programs are executable to implement a methodof using a computer system for modeling an in situ process for treatinga hydrocarbon containing formation, the method comprising: simulating aheat input rate to the formation from two or more heaters on thecomputer system, wherein heat is allowed to transfer from the heaters toa selected section of the formation; providing at least one desiredparameter of the in situ process to the computer system; and controllingthe heat input rate from the heaters to achieve at least one desiredparameter.
 6031. A carrier medium comprising program instructions,wherein the program instructions are computer-executable to implement amethod comprising: simulating a heat input rate to the formation fromtwo or more heaters on the computer system, wherein heat is allowed totransfer from the heaters to a selected section of the formation;providing at least one desired parameter of the in situ process to thecomputer system; and controlling the heat input rate from the heaters toachieve at least one desired parameter.
 6032. A system, comprising: aCPU; a data memory coupled to the CPU; and a system memory coupled tothe CPU, wherein the system memory is configured to store one or morecomputer programs executable by the CPU, and wherein the computerprograms are executable to implement a method of using a computer systemfor modeling an in situ process for treating a hydrocarbon containingformation, the method comprising: providing at least one heat inputproperty to the computer system; assessing heat injection rate data forthe formation using a first simulation method on the computer system;providing at least one property of the formation to the computer system;assessing at least one process characteristic of the in situ processfrom the heat injection rate data and at least one property of theformation using a second simulation method; and wherein the in situprocess comprises providing heat from one or more heaters to at leastone portion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heaters to a selectedsection of the formation.
 6033. A carrier medium comprising programinstructions, wherein the program instructions are computer-executableto implement a method comprising: providing at least one heat inputproperty to the computer system; assessing heat injection rate data forthe formation using a first simulation method on the computer system;providing at least one property of the formation to the computer system;assessing at least one process characteristic of the in situ processfrom the heat injection rate data and at least one property of theformation using a second simulation method; and wherein the in situprocess comprises providing heat from one or more heaters to at leastone portion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heaters to a selectedsection of the formation.
 6034. A system, comprising: a CPU; a datamemory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating a hydrocarbon containing formation, themethod comprising: providing one or more model parameters for the insitu process to the computer system; assessing one or more simulatedprocess characteristics based on one or more model parameters using asimulation method; modifying one or more model parameters such that atleast one simulated process characteristic matches or approximates atleast one real process characteristic; assessing one or more modifiedsimulated process characteristics based on the modified modelparameters; and wherein the in situ process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation.
 6035. Acarrier medium comprising program instructions, wherein the programinstructions are computer-executable to implement a method comprising:providing one or more model parameters for the in situ process to thecomputer system; assessing one or more simulated process characteristicsbased on one or more model parameters using a simulation method;modifying one or more model parameters such that at least one simulatedprocess characteristic matches or approximates at least one real processcharacteristic; assessing one or more modified simulated processcharacteristics based on the modified model parameters; and wherein thein situ process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation.
 6036. A system, comprising: a CPU;a data memory coupled to the CPU; and a system memory coupled to theCPU, wherein the system memory is configured to store one or morecomputer programs executable by the CPU, and wherein the computerprograms are executable to implement a method of using a computer systemfor modeling an in situ process for treating a hydrocarbon containingformation, the method comprising: assessing at least one operatingcondition of the in situ process using a simulation method based on oneor more model parameter; modifying at least one model parameter suchthat at least one simulated process characteristic of the in situprocess matches or approximates at least one real process characteristicof the in situ process; assessing one or more modified simulated processcharacteristics based on the modified model parameters; and wherein thein situ process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation simulated process characteristicsbased on the modified model parameters.
 6037. A carrier mediumcomprising program instructions, wherein the program instructions arecomputer-executable to implement a method comprising: assessing at leastone operating condition of the in situ process using a simulation methodbased on one or more model parameter; modifying at least one modelparameter such that at least one simulated process characteristic of thein situ process matches or approximates at least one real processcharacteristic of the in situ process; assessing one or more modifiedsimulated process characteristics based on the modified modelparameters; and wherein the in situ process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation.
 6038. Asystem, comprising: a CPU; a data memory coupled to the CPU; and asystem memory coupled to the CPU, wherein the system memory isconfigured to store one or more computer programs executable by the CPU,and wherein the computer programs are executable to implement a methodof using a computer system for modeling an in situ process for treatinga hydrocarbon containing formation, the method comprising: providing oneor more model parameters to the computer system; assessing one or morefirst process characteristics based on one or more model parametersusing a first simulation method on the computer system; assessing one ormore second process characteristics based on one or more modelparameters using a second simulation method on the computer system;modifying one or more model parameters such that at least one firstprocess characteristic matches or approximates at least one secondprocess characteristic; and wherein the in situ process comprisesproviding heat from one or more heaters to at least one portion of theformation, and wherein the in situ process comprises allowing the heatto transfer from the one or more heaters to a selected section of theformation.
 6039. A carrier medium comprising program instructions,wherein the program instructions are computer-executable to implement amethod comprising: providing one or more model parameters to thecomputer system; assessing one or more first process characteristicsbased on one or more model parameters using a first simulation method onthe computer system; assessing one or more second processcharacteristics based on one or more model parameters using a secondsimulation method on the computer system; modifying one or more modelparameters such that at least one first process characteristic matchesat least one second process characteristic; and wherein the in situprocess comprises providing heat from one or more heaters to at leastone portion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heaters to a selectedsection of the formation.
 6040. A system, comprising: a CPU; a datamemory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating a hydrocarbon containing formation, themethod comprising: providing to the computer system one or more valuesof at least one operating condition of the in situ process, wherein thein situ process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; assessing one or more values of atleast one process characteristic corresponding to one or more values ofat least one operating condition using a simulation method; providing adesired value of at least one process characteristic for the in situprocess to the computer system; and assessing a desired value of atleast one operating condition to achieve the desired value of at leastone process characteristic from the assessed values of at least oneprocess characteristic and the provided values of at least one operatingcondition.
 6041. A carrier medium comprising program instructions,wherein the program instructions are computer-executable to implement amethod comprising: providing to the computer system one or more valuesof at least one operating condition of the in situ process, wherein thein situ process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; assessing one or more values of atleast one process characteristic corresponding to one or more values ofat least one operating condition using a simulation method; providing adesired value of at least one process characteristic for the in situprocess to the computer system; and assessing a desired value of atleast one operating condition to achieve the desired value of at leastone process characteristic from the assessed values of at least oneprocess characteristic and the provided values of at least one operatingcondition.
 6042. A system, comprising: a CPU; a data memory coupled tothe CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for modeling an in situprocess for treating a hydrocarbon containing formation, the methodcomprising: providing a desired value of at least one processcharacteristic for the in situ process to the computer system, whereinthe in situ process comprises providing heat from one or more heaters toat least one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; and assessing a value of at leastone operating condition to achieve the desired value of at least oneprocess characteristic, wherein such assessing comprises using arelationship between at least one process characteristic and at leastone operating condition for the in situ process, wherein suchrelationship is stored on a database accessible by the computer system.6043. A carrier medium comprising program instructions, wherein theprogram instructions are computer-executable to implement a methodcomprising: providing a desired value of at least one processcharacteristic for the in situ process to the computer system, whereinthe in situ process comprises providing heat from one or more heaters toat least one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; and assessing a value of at leastone operating condition to achieve the desired value of at least oneprocess characteristic, wherein such assessing comprises using arelationship between at least one process characteristic and at leastone operating condition for the in situ process, wherein suchrelationship is stored on a database accessible by the computer system.6044. A method of using a computer system for operating an in situprocess for treating a hydrocarbon containing formation, comprising:operating the in situ process using one or more operating parameters,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; providing at leastone operating parameter of the in situ process to the computer system;and using at least one parameter with a simulation method and thecomputer system to provide assessed information about the in situprocess.
 6045. The method of claim 6044, wherein one or more of theoperating parameters comprise a thickness of a treated portion of theformation.
 6046. The method of claim 6044, wherein one or more of theoperating parameters comprise an area of a treated portion of theformation.
 6047. The method of claim 6044, wherein one or more of theoperating parameters comprise a volume of a treated portion of theformation.
 6048. The method of claim 6044, wherein one or more of theoperating parameters comprise a property of the formation.
 6049. Themethod of claim 6044, wherein one or more of the operating parameterscomprise a heat capacity of the formation.
 6050. The method of claim6044, wherein one or more of the operating parameters comprise apermeability of the formation.
 6051. The method of claim 6044, whereinone or more of the operating parameters comprise a density of theformation.
 6052. The method of claim 6044, wherein one or more of theoperating parameters comprise a thermal conductivity of the formation.6053. The method of claim 6044, wherein one or more of the operatingparameters comprise a porosity of the formation.
 6054. The method ofclaim 6044, wherein one or more of the operating parameters comprise apressure.
 6055. The method of claim 6044, wherein one or more of theoperating parameters comprise a temperature.
 6056. The method of claim6044, wherein one or more of the operating parameters comprise a heatingrate.
 6057. The method of claim 6044, wherein one or more of theoperating parameters comprise a process time.
 6058. The method of claim6044, wherein one or more of the operating parameters comprises alocation of producer wells.
 6059. The method of claim 6044, wherein oneor more of the operating parameters comprise an orientation of producerwells.
 6060. The method of claim 6044, wherein one or more of theoperating parameters comprise a ratio of producer wells to heater wells.6061. The method of claim 6044, wherein one or more of the operatingparameters comprise a spacing between heater wells.
 6062. The method ofclaim 6044, wherein one or more of the operating parameters comprise adistance between an overburden and horizontal heater wells.
 6063. Themethod of claim 6044, wherein one or more of the operating parameterscomprise a type of pattern of heater wells.
 6064. The method of claim6044, wherein one or more of the operating parameters comprise anorientation of heater wells.
 6065. The method of claim 6044, wherein oneor more of the operating parameters comprise a mechanical property.6066. The method of claim 6044, wherein one or more of the operatingparameters comprise subsidence of the formation.
 6067. The method ofclaim 6044, wherein one or more of the operating parameters comprisefracture progression in the formation.
 6068. The method of claim 6044,wherein one or more of the operating parameters comprise heave of theformation.
 6069. The method of claim 6044, wherein one or more of theoperating parameters comprise compaction of the formation.
 6070. Themethod of claim 6044, wherein one or more of the operating parameterscomprise shear deformation of the formation.
 6071. The method of claim6044, wherein the assessed information comprises information relating toproperties of the formation.
 6072. The method of claim 6044, wherein theassessed information comprises a relationship between one or moreoperating parameters and at least one other operating parameter. 6073.The method of claim 6044, wherein the computer system is remote from thein situ process.
 6074. The method of claim 6044, wherein the computersystem is located at or near the in situ process.
 6075. The method ofclaim 6044, wherein at least one parameter is provided to the computersystem using hardwire communication.
 6076. The method of claim 6044,wherein at least one parameter is provided to the computer system usinginternet communication.
 6077. The method of claim 6044, wherein at leastone parameter is provided to the computer system using wirelesscommunication.
 6078. The method of claim 6044, wherein the one or moreparameters are monitored using sensors in the formation.
 6079. Themethod of claim 6044, wherein at least one parameter is providedautomatically to the computer system.
 6080. The method of claim 6044,wherein using at least one parameter with a simulation method comprisesperforming a simulation and obtaining properties of the formation. 6081.A method of using a computer system for operating an in situ process fortreating a hydrocarbon containing formation, comprising: operating thein situ process using one or more operating parameters, wherein the insitu process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; providing at least one operatingparameter of the in situ process to the computer system; using at leastone parameter with a simulation method and the computer system toprovide assessed information about the in situ process; and using theassessed information to operate the in situ process.
 6082. The method ofclaim 6081, further comprising providing the assessed information to acomputer system used for controlling the in situ process.
 6083. Themethod of claim 6081, wherein the computer system is remote from the insitu process.
 6084. The method of claim 6081, wherein the computersystem is located at or near the in situ process.
 6085. The method ofclaim 6081, wherein using the assessed information to operate the insitu process comprises: modifying at least one operating parameter; andoperating the in situ process with at least one modified operatingparameter.
 6086. A method of using a computer system for operating an insitu process for treating a hydrocarbon containing formation, comprisingoperating the in situ process using one or more operating parameters,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; providing at leastone operating parameter of the in situ process to the computer system;using at least one parameter with a first simulation method and thecomputer system to provide assessed information about the in situprocess; and obtaining information from a second simulation method andthe computer system using the assessed information and a desiredparameter.
 6087. The method of claim 6086, further comprising using theobtained information to operate the in situ process.
 6088. The method ofclaim 6086, wherein the first simulation method is the same as thesecond simulation method.
 6089. The method of claim 6086, furthercomprising providing the obtained information to a computer system usedfor controlling the in situ process.
 6090. The method of claim 6086,wherein using the obtained information to operate the in situ processcomprises: modifying at least one operating parameter; and operating thein situ process with at least one modified operating parameter. 6091.The method of claim 6086, wherein the obtained information comprises atleast one operating parameter for use in the in situ process thatachieves the desired parameter.
 6092. The method of claim 6086, whereinthe computer system is remote from the in situ process.
 6093. The methodof claim 6086, wherein the computer system is located at or near the insitu process.
 6094. The method of claim 6086, wherein the desiredparameter comprises a selected gas to oil ratio.
 6095. The method ofclaim 6086, wherein the desired parameter comprises a selectedproduction rate of fluid produced from the formation.
 6096. The methodof claim 6086, wherein the desired parameter comprises a selectedproduction rate of fluid at a selected time produced from the formation.6097. The method of claim 6086, wherein the desired parameter comprisesa selected olefin content of produced fluids.
 6098. The method of claim6086, wherein the desired parameter comprises a selected carbon numberdistribution of produced fluids.
 6099. The method of claim 6086, whereinthe desired parameter comprises a selected ethene to ethane ratio ofproduced fluids.
 6100. The method of claim 6086, wherein the desiredparameter comprises a desired atomic carbon to hydrogen ratio ofproduced fluids.
 6101. The method of claim 6086, wherein the desiredparameter comprises a selected gas to oil ratio of produced fluids.6102. The method of claim 6086, wherein the desired parameter comprisesa selected pressure in the formation.
 6103. The method of claim 6086,wherein the desired parameter comprises a selected total mass recoveryfrom the formation.
 6104. The method of claim 6086, wherein the desiredparameter comprises a selected production rate of fluid produced fromthe formation.
 6105. A system, comprising: a CPU; a data memory coupledto the CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for operating an in situprocess for treating a hydrocarbon containing formation, comprising:operating the in situ process using one or more operating parameters,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; providing at leastone operating parameter of the in situ process to the computer system;and using at least one parameter with a simulation method and thecomputer system to provide assessed information about the in situprocess.
 6106. A carrier medium comprising program instructions, whereinthe program instructions are computer-executable to implement a methodcomprising: operating the in situ process using one or more operatingparameters, wherein the in situ process comprises providing heat fromone or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation;providing at least one operating parameter of the in situ process to thecomputer system; and using at least one parameter with a simulationmethod and the computer system to provide assessed information about thein situ process.
 6107. A system, comprising: a CPU; a data memorycoupled to the CPU; and a system memory coupled to the CPU, wherein thesystem memory is configured to store one or more computer programsexecutable by the CPU, and wherein the computer programs are executableto implement a method of using a computer system for operating an insitu process for treating a hydrocarbon containing formation,comprising: operating the in situ process using one or more operatingparameters, wherein the in situ process comprises providing heat fromone or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation;providing at least one operating parameter of the in situ process to thecomputer system; using at least one parameter with a simulation methodand the computer system to provide assessed information about the insitu process; and using the assessed information to operate the in situprocess.
 6108. A carrier medium comprising program instructions, whereinthe program instructions are computer-executable to implement a methodcomprising: operating the in situ process using one or more operatingparameters, wherein the in situ process comprises providing heat fromone or more heaters to at least one portion of the formation, andwherein the in situ process comprises allowing the heat to transfer fromthe one or more heaters to a selected section of the formation;providing at least one operating parameter of the in situ process to thecomputer system; using at least one parameter with a simulation methodand the computer system to provide assessed information about the insitu process; and using the assessed information to operate the in situprocess.
 6109. A system, comprising: a CPU; a data memory coupled to theCPU; and a system memory coupled to the CPU, wherein the system memoryis configured to store one or more computer programs executable by theCPU, and wherein the computer programs are executable to implement amethod of using a computer system for operating an in situ process fortreating a hydrocarbon containing formation, comprising: operating thein situ process using one or more operating parameters, wherein the insitu process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; providing at least one operatingparameter of the in situ process to the computer system; using at leastone parameter with a first simulation method and the computer system toprovide assessed information about the in situ process; and obtaininginformation from a second simulation method and the computer systemusing the assessed information and a desired parameter.
 6110. A carriermedium comprising program instructions, wherein the program instructionsare computer-executable to implement a method comprising: operating thein situ process using one or more operating parameters, wherein the insitu process comprises providing heat from one or more heaters to atleast one portion of the formation, and wherein the in situ processcomprises allowing the heat to transfer from the one or more heaters toa selected section of the formation; providing at least one operatingparameter of the in situ process to the computer system; using at leastone parameter with a first simulation method and the computer system toprovide assessed information about the in situ process; and obtaininginformation from a second simulation method and the computer systemusing the assessed information and a desired parameter.
 6111. A methodof modeling one or more stages of a process for treating a hydrocarboncontaining formation in situ with a simulation method using a computersystem, comprising: providing at least one property of the formation tothe computer system; providing at least one operating condition for theone or more stages of the in situ process to the computer system,wherein the in situ process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein the insitu process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; assessing at leastone process characteristic of the one or more stages using thesimulation method.
 6112. The method of claim 6111, wherein thesimulation method is a body-fitted finite difference simulation method.6113. The method of claim 6111, wherein the simulation method is areservoir simulation method.
 6114. The method of claim 6111, wherein thesimulation method is a space-fitted finite difference simulation method.6115. The method of claim 6111, wherein the simulation method simulatesheating of the formation.
 6116. The method of claim 6111, wherein thesimulation method simulates fluid flow in the formation.
 6117. Themethod of claim 6111, wherein the simulation method simulates masstransfer in the formation.
 6118. The method of claim 6111, wherein thesimulation method simulates heat transfer in the formation.
 6119. Themethod of claim 6111, wherein the simulation method simulates chemicalreactions in the one or more stages of the process in the formation.6120. The method of claim 6111, wherein the simulation method simulatesremoval of contaminants from the formation.
 6121. The method of claim6111, wherein the simulation method simulates recovery of heat from theformation.
 6122. The method of claim 6111, wherein the simulation methodsimulates injection of fluids into the formation.
 6123. The method ofclaim 6111, wherein the one or more stages comprise heating of theformation.
 6124. The method of claim 6111, wherein the one or morestages comprise generation of pyrolyzation fluids.
 6125. The method ofclaim 6111, wherein the one or more stages comprise remediation of theformation.
 6126. The method of claim 6111, wherein the one or morestages comprise shut-in of the formation.
 6127. The method of claim6111, wherein at least one operating condition of a remediation stage isthe flow rate of ground water into the formation.
 6128. The method ofclaim 6111, wherein at least one operating condition of a remediationstage is the flow rate of injected fluids into the formation.
 6129. Themethod of claim 6111, wherein at least one process characteristic of aremediation stage is the concentration of contaminants in the formation.6130. The method of claim 6111, further comprising: providing to thecomputer system at least one set of operating conditions for at leastone of the stages of the in situ process, wherein the in situ processcomprises providing heat from one or more heaters to at least oneportion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heaters to a selectedsection of the formation; providing to the computer system at least onedesired process characteristic for at least one of the stages of the insitu process; and assessing at least one additional operating conditionfor at least one of the stages that achieves at least one desiredprocess characteristic for at least one of the stages.
 6131. A method ofusing a computer system for modeling an in situ process for treating ahydrocarbon containing formation, comprising: providing at least oneproperty of the formation to a computer system; providing at least oneoperating condition to the computer system; assessing at least oneprocess characteristic of the in situ process, wherein the in situprocess comprises providing heat from one or more heaters to at leastone portion of the formation, and wherein the in situ process comprisesallowing the heat to transfer from the one or more heaters to a selectedsection of the formation; and assessing at least one deformationcharacteristic of the formation using a simulation method from at leastone property, at least one operating condition, and at least one processcharacteristic.
 6132. The method of claim 6131, wherein the in situprocess comprises two or more heaters.
 6133. The method of claim 6131,wherein the in situ process provides heat from one or more heaters to atleast one portion of the formation.
 6134. The method of claim 6131,wherein the simulation method comprises a finite element simulationmethod.
 6135. The method of claim 6131, wherein the formation comprisesa treated portion and an untreated portion.
 6136. The method of claim6131, wherein at least one deformation characteristic comprisessubsidence.
 6137. The method of claim 6131, wherein at least onedeformation characteristic comprises heave.
 6138. The method of claim6131, wherein at least one deformation characteristic comprisescompaction.
 6139. The method of claim 6131, wherein at least onedeformation characteristic comprises shear deformation.
 6140. The methodof claim 6131, wherein at least one operating condition comprises apressure.
 6141. The method of claim 6131, wherein at least one operatingcondition comprises a temperature.
 6142. The method of claim 6131,wherein at least one operating condition comprises a process time. 6143.The method of claim 6131, wherein at least one operating conditioncomprises a rate of pressure increase.
 6144. The method of claim 6131,wherein at least one operating condition comprises a heating rate. 6145.The method of claim 6131, wherein at least one operating conditioncomprises a width of a treated portion of the formation.
 6146. Themethod of claim 6131, wherein at least one operating condition comprisesa thickness of a treated portion of the formation.
 6147. The method ofclaim 6131, wherein at least one operating condition comprises athickness of an overburden of the formation.
 6148. The method of claim6131, wherein at least one process characteristic comprises a porepressure distribution in the formation.
 6149. The method of claim 6131,wherein at least one process characteristic comprises a temperaturedistribution in the formation.
 6150. The method of claim 6131, whereinat least one process characteristic comprises a heat input rate. 6151.The method of claim 6131, wherein at least one property comprises aphysical property of the formation.
 6152. The method of claim 6131,wherein at least one property comprises richness of the formation. 6153.The method of claim 6131, wherein at least one property comprises a heatcapacity.
 6154. The method of claim 6131, wherein at least one propertycomprises a thermal conductivity.
 6155. The method of claim 6131,wherein at least one property comprises a coefficient of thermalexpansion.
 6156. The method of claim 6131, wherein at least one propertycomprises a mechanical property.
 6157. The method of claim 6131, whereinat least one property comprises an elastic modulus.
 6158. The method ofclaim 6131, wherein at least one property comprises a Poisson's ratio.6159. The method of claim 6131, wherein at least one property comprisescohesion stress.
 6160. The method of claim 6131, wherein at least oneproperty comprises a friction angle.
 6161. The method of claim 6131,wherein at least one property comprises a cap eccentricity.
 6162. Themethod of claim 6131, wherein at least one property comprises a capyield stress.
 6163. The method of claim 6131, wherein at least oneproperty comprises a cohesion creep multiplier.
 6164. The method ofclaim 6131, wherein at least one property comprises a thermal expansioncoefficient.
 6165. A method of using a computer system for modeling anin situ process for treating a hydrocarbon containing formation,comprising: providing to the computer system at least one set ofoperating conditions for the in situ process, wherein the processcomprises providing heat from one or more heaters to at least oneportion of the formation, and wherein the process comprises allowing theheat to transfer from the one or more heaters to a selected section ofthe formation; providing to the computer system at least one desireddeformation characteristic for the in situ process; and assessing atleast one additional operating condition of the formation that achievesat least one desired deformation characteristic.
 6166. The method ofclaim 6165, further comprising operating the in situ system using atleast one additional operating condition.
 6167. The method of claim6165, wherein the in situ process comprises two or more heaters. 6168.The method of claim 6165, wherein the in situ process provides heat fromone or more heaters to at least one portion of the formation.
 6169. Themethod of claim 6165, wherein the in situ process allows heat totransfer from one or more heaters to a selected section of theformation.
 6170. The method of claim 6165, wherein at least one set ofoperating conditions comprises at least one set of pressures.
 6171. Themethod of claim 6165, wherein at least one set of operating conditionscomprises at least one set of temperatures.
 6172. The method of claim6165, wherein at least one set of operating conditions comprises atleast one set of heating rates.
 6173. The method of claim 6165, whereinat least one set of operating conditions comprises at least one set ofoverburden thicknesses.
 6174. The method of claim 6165, wherein at leastone set of operating conditions comprises at least one set ofthicknesses of a treated portion of the formation.
 6175. The method ofclaim 6165, wherein at least one set of operating conditions comprisesat least one set of widths of a treated portion of the formation. 6176.The method of claim 6165, wherein at least one set of operatingconditions comprises at least one set of radii of a treated portion ofthe formation.
 6177. The method of claim 6165, wherein at least onedesired deformation characteristic comprises a selected subsidence.6178. The method of claim 6165, wherein at least one desired deformationcharacteristic comprises a selected heave.
 6179. The method of claim6165, wherein at least one desired deformation characteristic comprisesa selected compaction.
 6180. The method of claim 6165, wherein at leastone desired deformation characteristic comprises a selected sheardeformation.
 6181. A method of using a computer system for modeling anin situ process for treating a hydrocarbon containing formation,comprising: providing one or more values of at least one operatingcondition; assessing one or more values of at least one deformationcharacteristic using a simulation method based on the one or more valuesof at least one operating condition; providing a desired value of atleast one deformation characteristic for the in situ process to thecomputer system, wherein the process comprises providing heat from oneor more heaters to at least one portion of the formation, and whereinthe process comprises allowing the heat to transfer from the one or moreheaters to a selected section of the formation; and assessing a desiredvalue of at least one operating condition that achieves the desiredvalue of at least one deformation characteristic from the determinedvalues of at least one deformation characteristic and the providedvalues of at least one operating condition.
 6182. The method of claim6181, further comprising operating the in situ process using the desiredvalue of at least one operating condition.
 6183. The method of claim6181, wherein the in situ process comprises two or more heaters. 6184.The method of claim 6181, wherein at least one operating conditioncomprises a pressure.
 6185. The method of claim 6181, wherein at leastone operating condition comprises a heat input rate.
 6186. The method ofclaim 6181, wherein at least one operating condition comprises atemperature.
 6187. The method of claim 6181, wherein at least oneoperating condition comprises a heating rate.
 6188. The method of claim6181, wherein at least one operating condition comprises an overburdenthickness.
 6189. The method of claim 6181, wherein at least oneoperating condition comprises a thickness of a treated portion of theformation.
 6190. The method of claim 6181, wherein at least oneoperating condition comprises a width of a treated portion of theformation.
 6191. The method of claim 6181, wherein at least oneoperating condition comprises a radius of a treated portion of theformation.
 6192. The method of claim 6181, wherein at least onedeformation characteristic comprises subsidence.
 6193. The method ofclaim 6181, wherein at least one deformation characteristic comprisesheave.
 6194. The method of claim 6181, wherein at least one deformationcharacteristic comprises compaction.
 6195. The method of claim 6181,wherein at least one deformation characteristic comprises sheardeformation.
 6196. The method of claim 6181, wherein a value of at leastone formation characteristic comprises the formation characteristic as afunction of time.
 6197. The method of claim 6181, further comprisingdetermining a value of at least one deformation characteristic based onthe desired value of at least one operating condition using thesimulation method.
 6198. The method of claim 6181, wherein determiningthe desired value of at least one operating condition comprisesinterpolating the desired value from the determined values of at leastone formation characteristic and the provided values of at least oneoperating condition.
 6199. A method of using a computer system formodeling an in situ process for treating a hydrocarbon containingformation, comprising: providing a desired value of at least onedeformation characteristic for the in situ process to the computersystem, wherein the in situ process comprises providing heat from one ormore heaters to at least one portion of the formation, and wherein thein situ process comprises allowing the heat to transfer from the one ormore heaters to a selected section of the formation; and assessing avalue of at least one operating condition to achieve the desired valueof at least one deformation characteristic from a database in memory onthe computer system comprising a relationship between at least onedeformation characteristic and at least one operating condition for thein situ process.
 6200. The method of claim 6199, further comprisingoperating the in situ system using the desired value of at least oneoperating condition.
 6201. The method of claim 6199, wherein the in situsystem comprises two or more heaters.
 6202. The method of claim 6199,wherein the relationship is determined from one or more simulations ofthe in situ process using a simulation method.
 6203. The method of claim6199, wherein the relationship comprises one or more values of at leastone deformation characteristic and corresponding values of at least oneoperating condition.
 6204. The method of claim 6199, wherein therelationship comprises an analytical function.
 6205. The method of claim6199, wherein determining a value of at least one operating conditioncomprises interpolating a value of at least one operating condition fromthe relationship.
 6206. A system, comprising: a CPU; a data memorycoupled to the CPU; and a system memory coupled to the CPU, wherein thesystem memory is configured to store one or more computer programsexecutable by the CPU, and wherein the computer programs are executableto implement a method of using a computer system for modeling an in situprocess for treating a hydrocarbon containing formation, the methodcomprising: providing at least one property of the formation to acomputer system; providing at least one operating condition to thecomputer system; determining at least one process characteristic of thein situ process, wherein the process comprises providing heat from oneor more heaters to at least one portion of the formation, and whereinthe process comprises allowing the heat to transfer from the one or moreheaters to a selected section of the formation; and determining at leastone deformation characteristic of the formation using a simulationmethod from at least one property, at least one operating condition, andat least one process characteristic.
 6207. A carrier medium comprisingprogram instructions, wherein the program instructions arecomputer-executable to implement a method comprising: providing at leastone property of the formation to a computer system; providing at leastone operating condition to the computer system; determining at least oneprocess characteristic of the in situ process, wherein the processcomprises providing heat from one or more heaters to at least oneportion of the formation, and wherein the process comprises allowing theheat to transfer from the one or more heaters to a selected section ofthe formation; and determining at least one deformation characteristicof the formation using a simulation method from at least one property,at least one operating condition, and at least one processcharacteristic.
 6208. A system, comprising: a CPU; a data memory coupledto the CPU; and a system memory coupled to the CPU, wherein the systemmemory is configured to store one or more computer programs executableby the CPU, and wherein the computer programs are executable toimplement a method of using a computer system for modeling an in situprocess for treating a hydrocarbon containing formation, the methodcomprising: providing to the computer system at least one set ofoperating conditions for the in situ process, wherein the processcomprises providing heat from one or more heaters to at least oneportion of the formation, and wherein the process comprises allowing theheat to transfer from the one or more heaters to a selected section ofthe formation; providing to the computer system at least one desireddeformation characteristic for the in situ process; and determining atleast one additional operating condition of the formation that achievesat least one desired deformation characteristic.
 6209. A carrier mediumcomprising program instructions, wherein the program instructions arecomputer-executable to implement a method comprising: providing to thecomputer system at least one set of operating conditions for the in situprocess, wherein the process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheaters to a selected section of the formation; providing to thecomputer system at least one desired deformation characteristic for thein situ process; and determining at least one additional operatingcondition of the formation that achieves at least one desireddeformation characteristic.
 6210. A system, comprising: a CPU; a datamemory coupled to the CPU; and a system memory coupled to the CPU,wherein the system memory is configured to store one or more computerprograms executable by the CPU, and wherein the computer programs areexecutable to implement a method of using a computer system for modelingan in situ process for treating a hydrocarbon containing formation, themethod comprising: providing one or more values of at least oneoperating condition; determining one or more values of at least onedeformation characteristic using a simulation method based on the one ormore values of at least one operating condition; providing a desiredvalue of at least one deformation characteristic for the in situ processto the computer system, wherein the process comprises providing heatfrom one or more heaters to at least one portion of the formation, andwherein the process comprises allowing the heat to transfer from the oneor more heaters to a selected section of the formation; and determininga desired value of at least one operating condition that achieves thedesired value of at least one deformation characteristic from thedetermined values of at least one deformation characteristic and theprovided values of at least one operating condition.
 6211. A carriermedium comprising program instructions, wherein the program instructionsare computer-executable to implement a method comprising: providing oneor more values of at least one operating condition; determining one ormore values of at least one deformation characteristic using asimulation method based on the one or more values of at least oneoperating condition; providing a desired value of at least onedeformation characteristic for the in situ process to the computersystem, wherein the process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheaters to a selected section of the formation; and determining adesired value of at least one operating condition that achieves thedesired value of at least one deformation characteristic from thedetermined values of at least one deformation characteristic and theprovided values of at least one operating condition.
 6212. A system,comprising: a CPU; a data memory coupled to the CPU; and a system memorycoupled to the CPU, wherein the system memory is configured to store oneor more computer programs executable by the CPU, and wherein thecomputer programs are executable to implement a method of using acomputer system for modeling an in situ process for treating ahydrocarbon containing formation, the method comprising: providing adesired value of at least one deformation characteristic for the in situprocess to the computer system, wherein the process comprises providingheat from one or more heaters to at least one portion of the formation,and wherein the process comprises allowing the heat to transfer from theone or more heaters to a selected section of the formation; anddetermining a value of at least one operating condition to achieve thedesired value of at least one deformation characteristic from a databasein memory on the computer system comprising a relationship between atleast one formation characteristic and at least one operating conditionfor the in situ process.
 6213. A carrier medium comprising programinstructions, wherein the program instructions are computer-executableto implement a method comprising: providing a desired value of at leastone deformation characteristic for the in situ process to the computersystem, wherein the process comprises providing heat from one or moreheaters to at least one portion of the formation, and wherein theprocess comprises allowing the heat to transfer from the one or moreheaters to a selected section of the formation; and determining a valueof at least one operating condition to achieve the desired value of atleast one deformation characteristic from a database in memory on thecomputer system comprising a relationship between at least one formationcharacteristic and at least one operating condition for the in situprocess.
 6214. A system configurable to provide heat to a hydrocarboncontaining formation, comprising: a first oxidizer configurable to beplaced in an opening in the formation, wherein the first oxidizer isconfigurable to oxidize a first fuel during use; a second oxidizerconfigurable to be placed in the opening, wherein the second oxidizer isconfigurable to oxidize a second fuel during use; and wherein the systemis configurable to allow heat from oxidation of the first fuel or thesecond fuel to transfer to the formation during use.
 6215. The system ofclaim 6214, wherein the system is configured to provide heat to thehydrocarbon containing formation.
 6216. The system of claim 6214,wherein the first oxidizer is configured to be placed in an opening inthe formation and wherein the first oxidizer is configured to oxidizethe first fuel during use.
 6217. The system of claim 6214, wherein thesecond oxidizer is configured to be placed in the opening and whereinthe second oxidizer is configured to oxidize the second fuel during use.6218. The system of claim 6214, wherein the system is configured toallow the heat from the oxidation to transfer to the formation duringuse.
 6219. The system of claim 6214, wherein the first oxidizercomprises a burner.
 6220. The system of claim 6214, wherein the firstoxidizer comprises an inline burner.
 6221. The system of claim 6214,wherein the second oxidizer comprises a burner.
 6222. The system ofclaim 6214, wherein the second oxidizer comprises a ring burner. 6223.The system of claim 6214, wherein a distance between the first oxidizerand the second oxidizer is less than about 250 meters.
 6224. The systemof claim 6214, further comprising a conduit configurable to be placed inthe opening.
 6225. The system of claim 6214, further comprising aconduit configurable to be placed in the opening, wherein the conduit isconfigurable to provide an oxidizing fluid to the first oxidizer duringuse.
 6226. The system of claim 6214, further comprising a conduitconfigurable to be placed in the opening, wherein the conduit isconfigurable to provide the first fuel to the first oxidizer during use.6227. The system of claim 6214, further comprising a conduitconfigurable to be placed in the opening, wherein the conduit isconfigurable to provide an oxidizing fluid to the second oxidizer duringuse.
 6228. The system of claim 6214, further comprising a conduitconfigurable to be placed in the opening, wherein the conduit isconfigurable to provide the second fuel to the second oxidizer duringuse.
 6229. The system of claim 6214, further comprising a third oxidizerconfigurable to be placed in the opening, wherein the third oxidizer isconfigurable to oxidize a third fuel during use.
 6230. The system ofclaim 6214, further comprising a fuel source, wherein the fuel source isconfigurable to provide the first fuel to the first oxidizer or thesecond fuel to the second oxidizer during use.
 6231. The system of claim6214, wherein the first fuel is different from the second fuel. 6232.The system of claim 6214, wherein the first fuel is different from thesecond fuel, wherein the second fuel comprises hydrogen.
 6233. Thesystem of claim 6214, wherein a flow of the first fuel is separatelycontrolled from a flow of the second fuel.
 6234. The system of claim6214, wherein the first oxidizer is configurable to be placed proximatean upper portion of the opening.
 6235. The system of claim 6214, whereinthe second oxidizer is configurable to be placed proximate a lowerportion of the opening.
 6236. The system of claim 6214, furthercomprising insulation configurable to be placed proximate the firstoxidizer.
 6237. The system of claim 6214, further comprising insulationconfigurable to be placed proximate the second oxidizer.
 6238. Thesystem of claim 6214, wherein products from oxidation of the first fuelor the second fuel are removed from the formation through the openingduring use.
 6239. The system of claim 6214, further comprising anexhaust conduit configurable to be coupled to the opening to allowexhaust fluid to flow from the formation through the exhaust conduitduring use.
 6240. The system of claim 6214, wherein the system isconfigured to allow the heat from the oxidation of the first fuel or thesecond fuel to transfer to the formation during use.
 6241. The system ofclaim 6214, wherein the system is configured to allow the heat from theoxidation to transfer to a pyrolysis zone in the formation during use.6242. The system of claim 6214, wherein the system is configured toallow the heat from the oxidation to transfer to a pyrolysis zone in theformation during use, and wherein the transferred heat causes pyrolysisof at least some hydrocarbons in the pyrolysis zone during use. 6243.The system of claim 6214, wherein at least some of the heat from theoxidation is generated at the first oxidizer.
 6244. The system of claim6214, wherein at least some of the heat from the oxidation is generatedat the second oxidizer.
 6245. The system of claim 6214, wherein acombination of heat from the first oxidizer and heat from the secondoxidizer substantially uniformly heats a portion of the formation duringuse.
 6246. The system of claim 6214, further comprising a first conduitconfigurable to be placed in the opening of the formation, wherein thefirst conduit is configurable to provide a first oxidizing fluid to thefirst oxidizer in the opening during use, and wherein the first conduitis further configurable to provide a second oxidizing fluid to thesecond oxidizer in the opening during use.
 6247. The system of claim6246, further comprising a fuel conduit configurable to be placed in theopening, wherein the fuel conduit is further configurable to provide thefirst fuel to the first oxidizer during use.
 6248. The system of claim6247, wherein the fuel conduit is further configurable to be placed inthe first conduit.
 6249. The system of claim 6247, wherein the firstconduit is further configurable to be placed in the fuel conduit. 6250.The system of claim 6246, further comprising a fuel conduit configurableto be placed in the opening, wherein the fuel conduit is furtherconfigurable to provide the second fuel to the second oxidizer duringuse.
 6251. The system of claim 6246, wherein the first conduit isfurther configurable to provide the first fuel to the first oxidizerduring use.
 6252. An in situ method for heating a hydrocarbon containingformation, comprising: providing a first oxidizing fluid to a firstoxidizer placed in an opening in the formation; providing a first fuelto the first oxidizer; oxidizing at least some of the first fuel in thefirst oxidizer; providing a second oxidizing fluid to a second oxidizerplaced in the opening in the formation; providing a second fuel to thesecond oxidizer; oxidizing at least some of the second fuel in thesecond oxidizer; and allowing heat from oxidation of the first fuel andthe second fuel to transfer to a portion of the formation.
 6253. Themethod of claim 6252, wherein the first oxidizing fluid is provided tothe first oxidizer through a conduit placed in the opening.
 6254. Themethod of claim 6252, wherein the second oxidizing fluid is provided tothe second oxidizer through a conduit placed in the opening.
 6255. Themethod of claim 6252, wherein the first fuel is provided to the firstoxidizer through a conduit placed in the opening.
 6256. The method ofclaim 6252, wherein the first fuel is provided to the second oxidizerthrough a conduit placed in the opening.
 6257. The method of claim 6252,wherein the first oxidizing fluid and the first fuel are provided to thefirst oxidizer through a conduit placed in the opening.
 6258. The methodof claim 6252, further comprising using exhaust fluid from the firstoxidizer as a portion of the second fuel used in the second oxidizer.6259. The method of claim 6252, further comprising allowing the heat totransfer substantially by conduction from the portion of the formationto a pyrolysis zone of the formation.
 6260. The method of claim 6252,further comprising initiating oxidation of the second fuel in the secondoxidizer with an ignition source.
 6261. The method of claim 6252,further comprising removing exhaust fluids through the opening. 6262.The method of claim 6252, further comprising removing exhaust fluidsthrough the opening, wherein the exhaust fluids comprise heat andallowing at least some heat in the exhaust fluids to transfer from theexhaust fluids to the first oxidizing fluid prior to oxidation in thefirst oxidizer.
 6263. The method of claim 6252, further comprisingremoving exhaust fluids comprising heat through the opening, allowing atleast some heat in the exhaust fluids to transfer from the exhaustfluids to the first oxidizing fluid prior to oxidation, and increasing athermal efficiency of heating the hydrocarbon containing formation.6264. The method of claim 6252, further comprising removing exhaustfluids through an exhaust conduit coupled to the opening.
 6265. Themethod of claim 6252, further comprising removing exhaust fluids throughan exhaust conduit coupled to the opening and providing at least aportion of the exhaust fluids to a fourth oxidizer to be used as afourth fuel in a fourth oxidizer, wherein the fourth oxidizer is locatedin a separate opening in the formation.
 6266. A system configurable toprovide heat to a hydrocarbon containing formation, comprising: anopening placed in the formation, wherein the opening comprises a firstelongated portion, a second elongated portion, and a third elongatedportion, wherein the second elongated portion diverges from the firstelongated portion in a first direction, wherein the third elongatedportion diverges from the first elongated portion in a second direction,and wherein the first direction is substantially different than thesecond direction; a first heater configurable to be placed in the secondelongated portion, wherein the first heater is configurable to heat atleast a portion of the formation during use; a second heaterconfigurable to be placed in the third elongated portion, wherein thesecond heater is configurable to heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer to the formation during use.
 6267. The system of claim6266, wherein the first heater and the second heater are configurable toheat to at least a portion of the formation during use.
 6268. The systemof claim 6266, wherein the second and the third elongated portions areoriented substantially horizontally within the formation.
 6269. Thesystem of claim 6266, wherein the first direction is about 180° oppositethe second direction.
 6270. The system of claim 6266, wherein the firstelongated portion is placed substantially within an overburden of theformation.
 6271. The system of claim 6266, wherein the transferred heatsubstantially uniformly heats a portion of the formation during use.6272. The system of claim 6266, wherein the first heater or the secondheater comprises a downhole combustor.
 6273. The system of claim 6266,wherein the first heater or the second heater comprises an insulatedconductor heater.
 6274. The system of claim 6266, wherein the firstheater or the second heater comprises a conductor-in-conduit heater.6275. The system of claim 6266, wherein the first heater or the secondheater comprises an elongated member heater.
 6276. The system of claim6266, wherein the first heater or the second heater comprises a naturaldistributed combustor heater.
 6277. The system of claim 6266, whereinthe first heater or the second heater comprises a flameless distributedcombustor heater.
 6278. The system of claim 6266, wherein the firstheater comprises a first oxidizer and the second heater comprises asecond oxidizer.
 6279. The system of claim 6278, wherein the secondelongated portion has a length of less than about 175 meters.
 6280. Thesystem of claim 6278, wherein the third elongated portion has a lengthof less than about 175 meters.
 6281. The system of claim 6278, furthercomprising a fuel conduit configurable to be placed in the opening,wherein the fuel conduit is further configurable to provide fuel to thefirst oxidizer during use.
 6282. The system of claim 6278, furthercomprising a fuel conduit configurable to be placed in the opening,wherein the fuel conduit is further configurable to provide fuel to thesecond oxidizer during use.
 6283. The system of claim 6278, furthercomprising a fuel source, wherein the fuel source is configurable toprovide fuel to the first oxidizer or the second oxidizer during use.6284. The system of claim 6278, further comprising a third oxidizerplaced within the first elongated portion of the opening.
 6285. Thesystem of claim 6284, further comprising a fuel conduit configurable tobe placed in the opening, wherein the fuel conduit is furtherconfigurable to provide fuel to the third oxidizer during use.
 6286. Thesystem of claim 6284, further comprising a first fuel sourceconfigurable to provide a first fuel to the first fuel conduit, a secondfuel source configurable to provide a second fuel to a second fuelconduit, and a third fuel source configurable to provide a third fuel toa third fuel conduit.
 6287. The system of claim 6286, wherein the firstfuel has a composition substantially different from the second fuel orthe third fuel.
 6288. The system of claim 6266, further comprisinginsulation configurable to be placed proximate the first heater. 6289.The system of claim 6266, further comprising insulation configurable tobe placed proximate the second heater.
 6290. The system of claim 6266,wherein a fuel is oxidized in the first heater or the second heater togenerate heat and wherein products from oxidation are removed from theformation through the opening during use.
 6291. The system of claim6266, wherein a fuel is oxidized in the first heater and the secondheater and wherein products from oxidation are removed from theformation through the opening during use.
 6292. The system of claim6266, further comprising an exhaust conduit configurable to be coupledto the opening to allow exhaust fluid to flow from the formation throughthe exhaust conduit during use.
 6293. The system of claim 6278, whereinthe system is configured to allow the heat from oxidation of fuel totransfer to the formation during use.
 6294. The system of claim 6266,wherein the system is configured to allow heat to transfer to apyrolysis zone in the formation during use.
 6295. The system of claim6266, wherein the system is configured to allow heat to transfer to apyrolysis zone in the formation during use, and wherein the transferredheat causes pyrolysis of at least some hydrocarbons within the pyrolysiszone during use.
 6296. The system of claim 6266, wherein a combinationof the heat generated from the first heater and the heat generated fromthe second heater substantially uniformly heats a portion of theformation during use.
 6297. The system of claim 6266, further comprisinga third heater placed in the second elongated portion.
 6298. The systemof claim 6297, wherein the third heater comprises a downhole combustor.6299. The system of claim 6297, further comprising a fourth heaterplaced in the third elongated portion.
 6300. The system of claim 6299,wherein the fourth heater comprises a downhole combustor.
 6301. Thesystem of claim 6266, wherein the first heater is configured to beplaced in the second elongated portion, wherein the first heater isconfigured to provide heat to at least a portion of the formation duringuse, wherein the second heater is configured to be placed in the thirdelongated portion, wherein the second heater is configured to provideheat to at least a portion of the formation during use, and wherein thesystem is configured to allow heat to transfer to the formation duringuse.
 6302. The system of claim 6266, wherein the second and the thirdelongated portions are located in a substantially similar plane. 6303.The system of claim 6302, wherein the opening comprises a fourthelongated portion and a fifth elongated portion, wherein the fourthelongated portion diverges from the first elongated portion in a thirddirection, wherein the fifth elongated portion diverges from the firstelongated portion in a fourth direction, and wherein the third directionis substantially different than the fourth direction.
 6304. The systemof claim 6303, wherein the fourth and fifth elongated portions arelocated in a plane substantially different than the second and the thirdelongated portions.
 6305. The system of claim 6303, wherein a thirdheater is configurable to be placed in the fourth elongated portion, andwherein a fourth heater is configurable to be placed in the fifthelongated portion.
 6306. An in situ method for heating a hydrocarboncontaining formation, comprising: providing heat from two or moreheaters placed in an opening in the formation, wherein the openingcomprises a first elongated portion, a second elongated portion, and athird elongated portion, wherein the second elongated portion divergesfrom the first elongated portion in a first direction, wherein the thirdelongated portion diverges from the first elongated portion in a seconddirection, and wherein the first direction is substantially differentthan the second direction; allowing heat from the two or more heaters totransfer to a portion of the formation; and wherein the two or moreheaters comprise a first heater placed in the second elongated portionand a second heater placed in the third elongated portion.
 6307. Themethod of claim 6306, wherein the second and the third elongatedportions are oriented substantially horizontally within the formation.6308. The method of claim 6306, wherein the first elongated portion islocated substantially within an overburden of the formation.
 6309. Themethod of claim 6306, further comprising substantially uniformly heatinga portion of the formation.
 6310. The method of claim 6306, wherein thefirst heater or the second heater comprises a downhole combustor. 6311.The method of claim 6306, wherein the first heater or the second heatercomprises an insulated conductor heater.
 6312. The method of claim 6306,wherein the first heater or the second heater comprises aconductor-in-conduit heater.
 6313. The method of claim 6306, wherein thefirst heater or the second heater comprises an elongated member heater.6314. The method of claim 6306, wherein the first heater or the secondheater comprises a natural distributed combustor heater.
 6315. Themethod of claim 6306, wherein the first heater or the second heatercomprises a flameless distributed combustor heater.
 6316. The method ofclaim 6306, wherein the first heater comprises a first oxidizer and thesecond heater comprises a second oxidizer.
 6317. The method of claim6306, wherein the first heater comprises a first oxidizer and the secondheater comprises a second oxidizer and further comprising providing fuelto the first oxidizer through a fuel conduit placed in the opening.6318. The method of claim 6306, wherein the first heater comprises afirst oxidizer and the second heater comprises a second oxidizer andfurther comprising providing fuel to the second oxidizer through a fuelconduit placed in the opening.
 6319. The method of claim 6306, whereinthe two or more heaters comprise oxidizers and further comprisingproviding fuel to the oxidizers from a fuel source.
 6320. The method ofclaim 6316, further comprising providing heat to a portion of theformation using a third oxidizer placed within the first elongatedportion of the opening.
 6321. The method of claim 6306, wherein thefirst heater comprises a first oxidizer and the second heater comprisesa second oxidizer further comprising: providing heat to a portion of theformation using a third oxidizer placed within the first elongatedportion of the opening; and providing fuel to the third oxidizer througha fuel conduit placed in the opening.
 6322. The method of claim 6306,wherein the two or more heaters comprise oxidizers, and furthercomprising providing heat by oxidizing a fuel within the oxidizers andremoving products of oxidation of fuel through the opening.
 6323. Themethod of claim 6306, wherein the two or more heaters compriseoxidizers, and further comprising removing products from oxidation offuel through an exhaust conduit coupled to the opening.
 6324. The methodof claim 6306, further comprising allowing the heat to transfer from theportion to a pyrolysis zone in the formation.
 6325. The method of claim6306, further comprising allowing the heat to transfer from the portionto a pyrolysis zone in the formation and pyrolyzing at least somehydrocarbons within the pyrolysis zone with the transferred heat. 6326.The method of claim 6306, further comprising allowing the heat totransfer to from the portion to a pyrolysis zone in the formation,pyrolyzing at least some hydrocarbons within the pyrolysis zone with thetransferred heat, and producing a portion of the pyrolyzed hydrocarbonsthrough a conduit placed in the first elongated portion.
 6327. Themethod of claim 6306, further comprising providing heat to a portion ofthe formation using a third heater placed in the second elongatedportion.
 6328. The method of claim 6327, wherein the third heatercomprises a downhole combustor.
 6329. The method of claim 6327, furthercomprising providing heat to a portion of the formation using a fourthheater placed in the third elongated portion.
 6330. The method of claim6329, wherein the fourth heater comprises a downhole combustor.
 6331. Asystem configurable to provide heat to a hydrocarbon containingformation, comprising: an oxidizer configurable to be placed in anopening in the formation, wherein the oxidizer is configurable tooxidize fuel to generate heat during use; a first conduit configurableto be placed in the opening of the formation, wherein the first conduitis configurable to provide oxidizing fluid to the oxidizer in theopening during use; a heater configurable to be placed in the openingand configurable to provide additional heat; and wherein the system isconfigurable to allow the generated heat and the additional heat totransfer to the formation during use.
 6332. The system of claim 6331,wherein the heater comprises an insulated conductor.
 6333. The system ofclaim 6331, wherein the heater comprises a conductor-in-conduit heater.6334. The system of claim 6331, wherein the heater comprises anelongated member heater.
 6335. The system of claim 6331, wherein theheater comprises a flameless distributed combustor.
 6336. The system ofclaim 6331, wherein the oxidizer is configurable to be placed proximatean upper portion of the opening.
 6337. The system of claim 6331, furthercomprising insulation configurable to be placed proximate the oxidizer.6338. The system of claim 6331, wherein the heater is configurable to becoupled to the first conduit.
 6339. The system of claim 6331, whereinproducts from the oxidation of the fuel are removed from the formationthrough the opening during use.
 6340. The system of claim 6331, furthercomprising an exhaust conduit configurable to be coupled to the openingto allow exhaust fluid to flow from the formation through the exhaustconduit during use.
 6341. The system of claim 6331, wherein the systemis configured to allow the generated heat and the additional heat totransfer to the formation during use.
 6342. The system of claim 6331,wherein the system is configured to allow the generated heat and theadditional heat to transfer to a pyrolysis zone in the formation duringuse.
 6343. The system of claim 6331, wherein the system is configured toallow the generated heat and the additional heat to transfer to apyrolysis zone in the formation during use, and wherein the transferredheat pyrolyzes of at least some hydrocarbons within the pyrolysis zoneduring use.
 6344. The system of claim 6331, wherein a combination of thegenerate heat and the additional heat substantially uniformly heats aportion of the formation during use.
 6345. The system of claim 6331,wherein the oxidizer is configured to be placed in the opening in theformation and wherein the oxidizer is configured to oxidize at leastsome fuel during use.
 6346. The system of claim 6331, wherein the firstconduit is configured to be placed in the opening of the formation andwherein the first conduit is configured to provide oxidizing fluid tothe oxidizer in the opening during use.
 6347. The system of claim 6331,wherein the heater is configured to be placed in the opening and whereinthe heater is configurable to provide heat to a portion of the formationduring use.
 6348. The system of claim 6331, wherein the system isconfigured to allow the heat from the oxidation of at least some fueland from the heater to transfer to the formation during use.
 6349. An insitu method for heating a hydrocarbon containing formation, comprising:allowing heat to transfer from a heater placed in an opening to aportion of the formation. providing oxidizing fluid to an oxidizerplaced in the opening in the formation; providing fuel to the oxidizer;oxidizing at least some fuel in the oxidizer; and allowing additionalheat from oxidation of at least some fuel to transfer to the portion ofthe formation.
 6350. The method of claim 6349, wherein the heatercomprises an insulated conductor.
 6351. The method of claim 6349,wherein the heater comprises a conductor-in-conduit heater.
 6352. Themethod of claim 6349, wherein the heater comprises an elongated memberheater.
 6353. The method of claim 6349, wherein the heater comprises aflameless distributed combustor.
 6354. The method of claim 6349, whereinthe oxidizer is placed proximate an upper portion of the opening. 6355.The method of claim 6349, further comprising allowing the additionalheat to transfer from the portion to a pyrolysis zone in the formation.6356. The method of claim 6349, further comprising allowing theadditional heat to transfer from the portion to a pyrolysis zone in theformation and pyrolyzing at least some hydrocarbons within the pyrolysiszone.
 6357. The method of claim 6349, further comprising substantiallyuniformly heating the portion of the formation.
 6358. The method ofclaim 6349, further comprising removing exhaust fluids through theopening.
 6359. The method of claim 6349, further comprising removingexhaust fluids through an exhaust annulus in the formation.
 6360. Themethod of claim 6349, further comprising removing exhaust fluids throughan exhaust conduit coupled to the opening.
 6361. A system configurableto provide heat to a hydrocarbon containing formation, comprising: aheater configurable to be placed in an opening in the formation, whereinthe heater is configurable to heat a portion of the formation to atemperature sufficient to sustain oxidation of hydrocarbons during use;an oxidizing fluid source configurable to provide an oxidizing fluid toa reaction zone of the formation to oxidize at least some hydrocarbonsin the reaction zone during use such that heat is generated in thereaction zone, and wherein at least some of the reaction zone has beenpreviously heated by the heater; a first conduit configurable to beplaced in the opening, wherein the first conduit is configurable toprovide the oxidizing fluid from the oxidizing fluid source to thereaction zone in the formation during use, wherein the flow of oxidizingfluid can be controlled along at least a segment of the first conduit;and wherein the system is configurable to allow the generated heat totransfer from the reaction zone to the formation during use.
 6362. Thesystem of claim 6361, wherein the system is configurable to providehydrogen to the reaction zone during use.
 6363. The system of claim6361, wherein the oxidizing fluid is transported through the reactionzone substantially by diffusion.
 6364. The system of claim 6361, whereinthe system is configurable to allow the generated heat to transfer fromthe reaction zone to a pyrolysis zone in the formation during use. 6365.The system of claim 6361, wherein the system is configurable to allowthe generated heat to transfer substantially by conduction from thereaction zone to the formation during use.
 6366. The system of claim6361, wherein a temperature within the reaction zone can be controlledalong at least a segment of the first conduit during use.
 6367. Thesystem of claim 6361, wherein a heating rate in at least a section ofthe formation proximate at least a segment of the first conduit becontrolled.
 6368. The system of claim 6361, wherein the oxidizing fluidis configurable to be transported through the reaction zonesubstantially by diffusion, and wherein a rate of diffusion of theoxidizing fluid can controlled by a temperature within the reactionzone.
 6369. The system of claim 6361, wherein the first conduitcomprises orifices, and wherein the orifices are configurable to providethe oxidizing fluid into the opening during use.
 6370. The system ofclaim 6361, wherein the first conduit comprises critical flow orifices,and wherein the critical flow orifices are positioned on the firstconduit such that a flow rate of the oxidizing fluid is controlled at aselected rate during use.
 6371. The system of claim 6361, furthercomprising a second conduit configurable to remove an oxidation productduring use.
 6372. The system of claim 6371, wherein the second conduitis further configurable to allow heat within the oxidation product totransfer to the oxidizing fluid in the first conduit during use. 6373.The system of claim 6371, wherein a pressure of the oxidizing fluid inthe first conduit and a pressure of the oxidation product in the secondconduit are controlled during use such that a concentration of theoxidizing fluid along the length of the first conduit is substantiallyuniform.
 6374. The system of claim 6371, wherein the oxidation productis substantially inhibited from flowing into portions of the formationbeyond the reaction zone during use.
 6375. The system of claim 6361,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone during use.
 6376. Thesystem of claim 6361, wherein the portion of the formation extendsradially from the opening a distance of less than approximately 3 m.6377. The system of claim 6361, wherein the reaction zone extendsradially from the opening a distance of less than approximately 3 m.6378. The system of claim 6361, wherein the system is configurable topyrolyze at least some hydrocarbons in a pyrolysis zone of theformation.
 6379. The system of claim 6361, wherein the heater isconfigured to be placed in an opening in the formation and wherein theheater is configured to provide the heat to at least the portion of theformation during use.
 6380. The system of claim 6361, wherein a firstconduit is configured to be placed in the opening and wherein the firstconduit is configured to provide the oxidizing fluid from the oxidizingfluid source to the reaction zone in the formation during use.
 6381. Thesystem of claim 6361, wherein the flow of oxidizing fluid is controlledalong at least a segment of the length of the first conduit and whereinthe system is configured to allow the additional heat to transfer fromthe reaction zone to the formation during use.
 6382. An in situ methodfor providing heat to a hydrocarbon containing formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons with an oxidizing fluid within theportion of the formation; providing the oxidizing fluid to a reactionzone in the formation; controlling a flow of the oxidizing fluid alongat least a length of the reaction zone; generating heat within thereaction zone; and allowing the generated heat to transfer to theformation.
 6383. The method of claim 6382, further comprising allowingthe oxidizing fluid to react with at least some of the hydrocarbons inthe reaction zone to generate the heat in the reaction zone.
 6384. Themethod of claim 6382, wherein at least a section of the reaction zone isproximate an opening in the formation.
 6385. The method of claim 6382,further comprising transporting the oxidizing fluid through the reactionzone substantially by diffusion.
 6386. The method of claim 6382, furthercomprising transporting the oxidizing fluid through the reaction zonesubstantially by diffusion, and controlling a rate of diffusions of theoxidizing fluid by controlling a temperature within the reaction zone.6387. The method of claim 6382, wherein the generated heat transfersfrom the reaction zone to a pyrolysis zone in the formation.
 6388. Themethod of claim 6382, wherein the generated heat transfers from thereaction zone to the formation substantially by conduction.
 6389. Themethod of claim 6382, further comprising controlling a temperature alongat least a length of the reaction zone.
 6390. The method of claim 6382,further comprising controlling a flow of the oxidizing fluid along atleast a length of the reaction zone, and controlling a temperature alongat least a length of the reaction zone.
 6391. The method of claim 6382,further comprising controlling a heating rate along at least a length ofthe reaction zone.
 6392. The method of claim 6382, wherein the oxidizingfluid is provided through a conduit placed within an opening in theformation, wherein the conduit comprises orifices.
 6393. The method ofclaim 6382, further comprising controlling a rate of oxidation byproviding the oxidizing fluid to the reaction zone from a conduit havingcritical flow orifices.
 6394. The method of claim 6382, wherein theoxidizing fluid is provided to the reaction zone through a conduitplaced within the formation, and further comprising positioning criticalflow orifices on the conduit such that the flow rate of the oxidizingfluid to at least a length of the reaction zone is controlled at aselected flow rate.
 6395. The method of claim 6382, wherein theoxidizing fluid is provided to the reaction zone from a conduit placedwithin an opening in the formation, and further comprising sizingcritical flow orifices on the conduit such that the flow rate of theoxidizing fluid to at least a length of the reaction zone is controlledat a selected flow rate.
 6396. The method of claim 6382, furthercomprising increasing a volume of the reaction zone, and increasing theflow of the oxidizing fluid to the reaction zone such that a rate ofoxidation within the reaction zone is substantially constant over time.6397. The method of claim 6382, further comprising maintaining asubstantially constant rate of oxidation within the reaction zone overtime.
 6398. The method of claim 6382, wherein a conduit is placed in anopening in the formation, and further comprising cooling the conduitwith the oxidizing fluid to reduce heating of the conduit by oxidation.6399. The method of claim 6382, further comprising removing an oxidationproduct from the formation through a conduit placed in an opening in theformation.
 6400. The method of claim 6382, further comprising removingan oxidation product from the formation through a conduit placed in anopening in the formation and substantially inhibiting the oxidationproduct from flowing into a surrounding portion of the formation. 6401.The method of claim 6382, further comprising inhibiting the oxidizingfluid from flowing into a surrounding portion of the formation. 6402.The method of claim 6382, further comprising removing at least somewater from the formation prior to heating the portion.
 6403. The methodof claim 6382, further comprising providing additional heat to theformation from an electric heater placed in the opening.
 6404. Themethod of claim 6382, further comprising providing additional heat tothe formation from an electric heater placed in an opening in theformation such that the oxidizing fluid continuously oxidizes at least aportion of the hydrocarbons in the reaction zone.
 6405. The method ofclaim 6382, further comprising providing additional heat to theformation from an electric heater placed in the opening to maintain aconstant heat rate in the formation.
 6406. The method of claim 6405,further comprising providing electricity to the electric heater using awind powered device.
 6407. The method of claim 6405, further comprisingproviding electricity to the electric heater using a solar powereddevice.
 6408. The method of claim 6382, further comprising maintaining atemperature within the portion above about the temperature sufficient tosupport the reaction of hydrocarbons with the oxidizing fluid.
 6409. Themethod of claim 6382, further comprising providing additional heat tothe formation from an electric heater placed in the opening andcontrolling the additional heat such that a temperature of the portionis greater than about the temperature sufficient to support the reactionof hydrocarbons with the oxidizing fluid.
 6410. The method of claim6382, further comprising removing oxidation products from the formation,and generating electricity using oxidation products removed from theformation.
 6411. The method of claim 6382, further comprising removingoxidation products from the formation, and using at least some of theremoved oxidation products in an air compressor.
 6412. The method ofclaim 6382, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone over time.
 6413. The method of claim 6382, further comprisingassessing a temperature in or proximate an opening in the formation,wherein the flow of oxidizing fluid along at least a section of thereaction zone is controlled as a function of the assessed temperature.6414. The method of claim 6382, further comprising assessing atemperature in or proximate an opening in the formation, and increasingthe flow of oxidizing fluid as the assessed temperature decreases. 6415.The method of claim 6382, further comprising controlling the flow ofoxidizing fluid to maintain a temperature in or proximate an opening inthe formation at a temperature less than a pre-selected temperature.6416. A system configurable to provide heat to a hydrocarbon containingformation, comprising: a heater configurable to be placed in an openingin the formation, wherein the heater is configurable to provide heat toat least a portion of the formation during use; an oxidizing fluidsource configurable to provide an oxidizing fluid to a reaction zone ofthe formation to generate heat in the reaction zone during use, whereinat least a portion of the reaction zone has been previously heated bythe heater during use; a conduit configurable to be placed in theopening, wherein the conduit is configurable to provide the oxidizingfluid from the oxidizing fluid source to the reaction zone in theformation during use; wherein the system is configurable to providemolecular hydrogen to the reaction zone during use; and wherein thesystem is configurable to allow the generated heat to transfer from thereaction zone to the formation during use.
 6417. The system of claim6416, wherein the system is configurable to allow the oxidizing fluid tobe transported through the reaction zone substantially by diffusionduring use.
 6418. The system of claim 6416, wherein the system isconfigurable to allow the generated heat to transfer from the reactionzone to a pyrolysis zone in the formation during use.
 6419. The systemof claim 6416, wherein the system is configurable to allow the generatedheat to transfer substantially by conduction from the reaction zone tothe formation during use.
 6420. The system of claim 6416, wherein theflow of oxidizing fluid can be controlled along at least a segment ofthe conduit such that a temperature can be controlled along at least asegment of the conduit during use.
 6421. The system of claim 6416,wherein a flow of oxidizing fluid can be controlled along at least asegment of the conduit such that a heating rate in at least a section ofthe formation can be controlled.
 6422. The system of claim 6416, whereinthe oxidizing fluid is configurable to move through the reaction zonesubstantially by diffusion during use, wherein a rate of diffusion cancontrolled by a temperature of the reaction zone.
 6423. The system ofclaim 6416, wherein the conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening during use.
 6424. The system of claim 6416, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configurable to control a flow of the oxidizing fluid such that arate of oxidation in the formation is controlled during use.
 6425. Thesystem of claim 6416, wherein the conduit comprises a first conduit anda second conduit, wherein the second conduit is configurable to removean oxidation product during use.
 6426. The system of claim 6416, whereinthe oxidizing fluid is substantially inhibited from flowing from thereaction zone into a surrounding portion of the formation.
 6427. Thesystem of claim 6416, wherein at least the portion of the formationextends radially from the opening a distance of less than approximately3 m.
 6428. The system of claim 6416, wherein the reaction zone extendsradially from the opening a distance of less than approximately 3 m.6429. The system of claim 6416, wherein the system is configurable toallow transferred heat to pyrolyze at least some hydrocarbons in apyrolysis zone of the formation.
 6430. The system of claim 6416, whereinthe heater is configured to be placed in an opening in the formation andwherein the heater is configured to provide heat to at least a portionof the formation during use.
 6431. The system of claim 6416, wherein theconduit is configured to be placed in the opening to provide at leastsome of the oxidizing fluid from the oxidizing fluid source to thereaction zone in the formation during use, and wherein the flow of atleast some of the oxidizing fluid can be controlled along at least asegment of the first conduit.
 6432. The system of claim 6416, whereinthe system is configured to allow heat to transfer from the reactionzone to the formation during use.
 6433. The system of claim 6416,wherein the heater is configured to be placed in an opening in theformation and wherein the heater is configured to provide heat to atleast a portion of the formation during use.
 6434. The system of claim6416, wherein the conduit is configured to be placed in the opening andwherein the conduit is configured to provide the oxidizing fluid fromthe oxidizing fluid source to the reaction zone in the formation duringuse.
 6435. The system of claim 6416, wherein the flow of oxidizing fluidcan be controlled along at least a segment of the conduit.
 6436. Thesystem of claim 6416, wherein the system is configured to allow heat totransfer from the reaction zone to the formation during use.
 6437. Thesystem of claim 6416, wherein at least some of the provided hydrogen isproduced in the pyrolysis zone during use.
 6438. The system of claim6416, wherein at least some of the provided hydrogen is produced in thereaction zone during use.
 6439. The system of claim 6416, wherein atleast some of the provided hydrogen is produced in at least the heatedportion of the formation during use.
 6440. The system of claim 6416,wherein the system is configurable to provide hydrogen to the reactionzone during use such that production of carbon dioxide in the reactionzone is inhibited.
 6441. An in situ method for heating a hydrocarboncontaining formation, comprising: heating a portion of the formation toa temperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid; providing theoxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons inthe reaction zone to generate heat in the reaction zone; providingmolecular hydrogen to the reaction zone; and transferring the generatedheat from the reaction zone to a pyrolysis zone in the formation. 6442.The method of claim 6441, further comprising producing the molecularhydrogen in the pyrolysis zone.
 6443. The method of claim 6441, furthercomprising producing the molecular hydrogen in the reaction zone. 6444.The method of claim 6441, further comprising producing the molecularhydrogen in at least the heated portion of the formation.
 6445. Themethod of claim 6441, further comprising inhibiting production of carbondioxide in the reaction zone.
 6446. The method of claim 6441, furthercomprising allowing the oxidizing fluid to transfer through the reactionzone substantially by diffusion.
 6447. The method of claim 6441, furthercomprising allowing the oxidizing fluid to transfer through the reactionzone by diffusion, wherein a rate of diffusion is controlled by atemperature of the reaction zone.
 6448. The method of claim 6441,wherein at least some of the generated heat transfers to the pyrolysiszone substantially by conduction.
 6449. The method of claim 6441,further comprising controlling a flow of the oxidizing fluid along atleast a segment reaction zone such that a temperature is controlledalong at least a segment of the reaction zone.
 6450. The method of claim6441, further comprising controlling a flow of the oxidizing fluid alongat least a segment of the reaction zone such that a heating rate iscontrolled along at least a segment of the reaction zone.
 6451. Themethod of claim 6441, further comprising allowing at least someoxidizing fluid to flow into the formation through orifices in a conduitplaced in an opening in the formation.
 6452. The method of claim 6441,further comprising controlling a flow of the oxidizing fluid into theformation using critical flow orifices on a conduit placed in theopening such that a rate of oxidation is controlled.
 6453. The method ofclaim 6441, further comprising controlling a flow of the oxidizing fluidinto the formation with a spacing of critical flow orifices on a conduitplaced in an opening in the formation.
 6454. The method of claim 6441,further comprising controlling a flow of the oxidizing fluid with adiameter of critical flow orifices in a conduit placed in an opening inthe formation.
 6455. The method of claim 6441, further comprisingincreasing a volume of the reaction zone, and increasing the flow of theoxidizing fluid to the reaction zone such that a rate of oxidationwithin the reaction zone is substantially constant over time.
 6456. Themethod of claim 6441, wherein a conduit is placed in an opening in theformation, and further comprising cooling the conduit with the oxidizingfluid to reduce heating of the conduit by oxidation.
 6457. The method ofclaim 6441, further comprising removing an oxidation product from theformation through a conduit placed in an opening in the formation. 6458.The method of claim 6441, further comprising removing an oxidationproduct from the formation through a conduit placed in an opening in theformation and inhibiting the oxidation product from flowing into asurrounding portion of the formation beyond the reaction zone.
 6459. Themethod of claim 6441, further comprising inhibiting the oxidizing fluidfrom flowing into a surrounding portion of the formation beyond thereaction zone.
 6460. The method of claim 6441, further comprisingremoving at least some water from the formation prior to heating theportion.
 6461. The method of claim 6441, further comprising providingadditional heat to the formation from an electric heater placed in theopening.
 6462. The method of claim 6441, further comprising providingadditional heat to the formation from an electric heater placed in theopening and continuously oxidizing at least a portion of thehydrocarbons in the reaction zone.
 6463. The method of claim 6441,further comprising providing additional heat to the formation from anelectric heater placed in an opening in the formation and maintaining aconstant heat rate within the pyrolysis zone.
 6464. The method of claim6441, further comprising providing additional heat to the formation froman electric heater placed in the opening such that the oxidation of atleast a portion of the hydrocarbons does not burn out.
 6465. The methodof claim 6441, further comprising removing oxidation products from theformation and generating electricity using at least some oxidationproducts removed from the formation.
 6466. The method of claim 6441,further comprising removing oxidation products from the formation andusing at least some oxidation products removed from the formation in anair compressor.
 6467. The method of claim 6441, further comprisingincreasing a flow of the oxidizing fluid in the reaction zone toaccommodate an increase in a volume of the reaction zone over time.6468. The method of claim 6441, further comprising increasing a volumeof the reaction zone such that an amount of heat provided to theformation increases.
 6469. The method of claim 6441, further comprisingassessing a temperature in or proximate the opening, and controlling theflow of oxidizing fluid as a function of the assessed temperature. 6470.The method of claim 6441, further comprising assessing a temperature inor proximate the opening, and increasing the flow of oxidizing fluid asthe assessed temperature decreases.
 6471. The method of claim 6441,further comprising controlling the flow of oxidizing fluid to maintain atemperature in or proximate the opening at a temperature less than apre-selected temperature.
 6472. A system configurable to heat ahydrocarbon containing formation, comprising: a heater configurable tobe placed in an opening in the formation, wherein the heater isconfigurable to provide heat to at least a portion of the formationduring use; an oxidizing fluid source, wherein an oxidizing fluid isselected to oxidize at least some hydrocarbons at a reaction zone duringuse such that heat is generated in the reaction zone; a first conduitconfigurable to be placed in the opening, wherein the first conduit isconfigurable to provide the oxidizing fluid from the oxidizing fluidsource to the reaction zone in the formation during use; and; a secondconduit configurable to be placed in the opening, wherein the secondconduit is configurable to remove a product of oxidation from theopening during use; and wherein the system is configurable to allow thegenerated heat to transfer from the reaction zone to the formationduring use.
 6473. The system of claim 6472, wherein the second conduitis configurable to control the concentration of oxygen in the openingduring use such that the concentration of oxygen in the opening issubstantially constant in the opening.
 6474. The system of claim 6472,wherein the second conduit comprises orifices, and wherein the secondconduit comprises a greater concentration of orifices towards an upperend of the second conduit.
 6475. The system of claim 6472, wherein thefirst conduit comprises orifices that direct oxidizing fluid in adirection substantially opposite the second conduit.
 6476. The system ofclaim 6472, wherein the second conduit comprises orifices that removethe oxidation product from a direction substantially opposite the firstconduit.
 6477. The system of claim 6472, wherein the second conduit isconfigurable to remove a product of oxidation from the opening duringuse such that the reaction zone comprises a substantially uniformtemperature profile.
 6478. The system of claim 6472, wherein a flow ofthe oxidizing fluid can be varied along a portion of a length of thefirst conduit.
 6479. The system of claim 6472, wherein the oxidizingfluid is configurable to generate heat in the reaction zone such thatthe oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 6480. The system of claim 6472, wherein thesystem is configurable to allow heat to transfer from the reaction zoneto a pyrolysis zone in the formation during use.
 6481. The system ofclaim 6472, wherein the system is configurable to allow heat to transfersubstantially by conduction from the reaction zone to the formationduring use.
 6482. The system of claim 6472, wherein a flow of oxidizingfluid can be controlled along at least a portion of a length of thefirst conduit such that a temperature can be controlled along at least aportion of the length of the first conduit during use.
 6483. The systemof claim 6472, wherein a flow of oxidizing fluid can be controlled alongat least a portion of the length of the first conduit such that aheating rate in at least a portion of the formation can be controlled.6484. The system of claim 6472, wherein the oxidizing fluid isconfigurable to generate heat in the reaction zone during use such thatthe oxidizing fluid is transported through the reaction zone during usesubstantially by diffusion, wherein a rate of diffusion can controlledby a temperature of the reaction zone.
 6485. The system of claim 6472,wherein the first conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening duringuse.
 6486. The system of claim 6472, wherein the first conduit comprisescritical flow orifices, and wherein the critical flow orifices areconfigurable to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled during use.
 6487. The systemof claim 6472, wherein the second conduit is further configurable toremove an oxidation product such that the oxidation product transfersheat to the oxidizing fluid in the first conduit during use.
 6488. Thesystem of claim 6472, wherein a pressure of the oxidizing fluid in thefirst conduit and a pressure of the oxidation product in the secondconduit are controlled during use such that a concentration of theoxidizing fluid in along the length of the conduit is substantiallyuniform.
 6489. The system of claim 6472, wherein the oxidation productis substantially inhibited from flowing into portions of the formationbeyond the reaction zone during use.
 6490. The system of claim 6472,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone during use.
 6491. Thesystem of claim 6472, wherein the portion of the formation extendsradially from the opening a distance of less than approximately 3 m.6492. The system of claim 6472, wherein the reaction zone extendsradially from the opening a distance of less than approximately 3 m.6493. The system of claim 6472, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 6494. The system of claim 6472,wherein the heater is configured to be placed in an opening in theformation and wherein the heater is configured to provide heat to atleast a portion of the formation during use.
 6495. The system of claim6472, wherein the first conduit is configured to be placed in theopening, and wherein the first conduit is configured to provide theoxidizing fluid from the oxidizing fluid source to the reaction zone inthe formation during use.
 6496. The system of claim 6472, wherein theflow of oxidizing fluid can be controlled along at least a segment ofthe first conduit.
 6497. The system of claim 6472, wherein the secondconduit is configured to be placed in the opening, and wherein thesecond conduit is configured to remove a product of oxidation from theopening during use.
 6498. The system of claim 6472, wherein the systemis configured to allow heat to transfer from the reaction zone to theformation during use.
 6499. An in situ method for heating a hydrocarboncontaining formation, comprising: heating a portion of the formation toa temperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid; providing theoxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons inthe reaction zone to generate heat in the reaction zone; removing anoxidation product from the opening; and transferring the generated heatfrom the reaction zone to the formation.
 6500. The method of claim 6499,further comprising removing the oxidation product such that aconcentration of oxygen in the opening is substantially constant in theopening.
 6501. The method of claim 6499, further comprising removing theoxidation product from the opening and maintaining a substantiallyuniform temperature profile within the reaction zone.
 6502. The methodof claim 6499, further comprising transporting the oxidizing fluidthrough the reaction zone substantially by diffusion.
 6503. The methodof claim 6499, further comprising transporting the oxidizing fluidthrough the reaction zone by diffusion, wherein a rate of diffusion iscontrolled by a temperature of the reaction zone.
 6504. The method ofclaim 6499, further comprising allowing heat to transfer from thereaction zone to a pyrolysis zone in the formation.
 6505. The method ofclaim 6499, further comprising allowing heat to transfer from thereaction zone to the formation substantially by conduction.
 6506. Themethod of claim 6499, further comprising controlling a flow of theoxidizing fluid along at least a portion of the length of the reactionzone such that a temperature is controlled along at least a portion ofthe length of the reaction zone.
 6507. The method of claim 6499, furthercomprising controlling a flow of the oxidizing fluid along at least aportion of the length of the reaction zone such that a heating rate iscontrolled along at least a portion of the length of the reaction zone.6508. The method of claim 6499, further comprising allowing at least aportion of the oxidizing fluid into the opening through orifices of aconduit placed in the opening.
 6509. The method of claim 6499, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices in a conduit placed in the opening such that a rate ofoxidation is controlled.
 6510. The method of claim 6499, furthercomprising controlling a flow of the oxidizing fluid with a spacing ofcritical flow orifices in a conduit placed in the opening.
 6511. Themethod of claim 6499, further comprising controlling a flow of theoxidizing fluid with a diameter of critical flow orifices in a conduitplaced in the opening.
 6512. The method of claim 6499, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 6513. The method of claim 6499, wherein a conduit isplaced in the opening, and further comprising cooling the conduit withthe oxidizing fluid to reduce heating of the conduit by oxidation. 6514.The method of claim 6499, further comprising removing an oxidationproduct from the formation through a conduit placed in the opening.6515. The method of claim 6499, further comprising removing an oxidationproduct from the formation through a conduit placed in the opening andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 6516. The method ofclaim 6499, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 6517. The method of claim 6499, further comprising removing waterfrom the formation prior to heating the portion.
 6518. The method ofclaim 6499, further comprising providing additional heat to theformation from an electric heater placed in the opening.
 6519. Themethod of claim 6499, further comprising providing additional heat tothe formation from an electric heater placed in the opening such thatthe oxidizing fluid continuously oxidizes at least a portion of thehydrocarbons in the reaction zone.
 6520. The method of claim 6499,further comprising providing additional heat to the formation from anelectric heater placed in the opening such that a constant heat rate inthe formation is maintained.
 6521. The method of claim 6499, furthercomprising providing additional heat to the formation from an electricheater placed in the opening such that the oxidation of at least aportion of the hydrocarbons does not burn out.
 6522. The method of claim6499, further comprising generating electricity using oxidation productsremoved from the formation.
 6523. The method of claim 6499, furthercomprising using oxidation products removed from the formation in an aircompressor.
 6524. The method of claim 6499, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone over time.
 6525. The methodof claim 6499, further comprising increasing the amount of heat providedto the formation by increasing the reaction zone.
 6526. The method ofclaim 6499, further comprising assessing a temperature in or proximatethe opening, and controlling the flow of oxidizing fluid as a functionof the assessed temperature.
 6527. The method of claim 6499, furthercomprising assessing a temperature in or proximate the opening, andincreasing the flow of oxidizing fluid as the assessed temperaturedecreases.
 6528. The method of claim 6499, further comprisingcontrolling the flow of oxidizing fluid to maintain a temperature in orproximate the opening at a temperature less than a pre-selectedtemperature.
 6529. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least one portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;controlling the heat from the one or more heaters such that an averagetemperature within at least a selected section of the formation is lessthan about 375° C.; producing a mixture from the formation from aproduction well; and controlling heating in or proximate the productionwell to produce a selected yield of non-condensable hydrocarbons in theproduced mixture.
 6530. The method of claim 6529, further comprisingcontrolling heating in or proximate the production well to produce aselected yield of condensable hydrocarbons in the produced mixture.6531. The method of claim 6529, wherein the mixture comprises more thanabout 50 weight percent non-condensable hydrocarbons.
 6532. The methodof claim 6529, wherein the mixture comprises more than about 50 weightpercent condensable hydrocarbons.
 6533. The method of claim 6529,wherein the average temperature and a pressure within the formation arecontrolled such that production of carbon dioxide is substantiallyinhibited.
 6534. The method of claim 6529, heating in or proximate theproduction well is controlled such that production of carbon dioxide issubstantially inhibited.
 6535. The method of claim 6529, wherein atleast a portion of the mixture produced from a first portion of theformation at a lower temperature is recycled into a second portion ofthe formation at a higher temperature such that production of carbondioxide is substantially inhibited.
 6536. The method of claim 6529,wherein the mixture comprises a volume ratio of molecular hydrogen tocarbon monoxide of about 2 to 1, and wherein producing the mixture iscontrolled such that the volume ratio is maintained between about 1.8 to1 and about 2.2 to
 1. 6537. The method of claim 6529, wherein the heatprovided from at least one heater is transferred to the formationsubstantially by conduction.
 6538. The method of claim 6529, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 6539. A method of treating a hydrocarbon containing formationin situ, comprising: providing heat from one or more heaters to at leastone portion of the formation; allowing the heat to transfer from the oneor more heaters to a selected section of the formation; controlling theheat from the one or more heaters such that an average temperaturewithin at least a selected section of the formation is less than about375° C.; and producing a mixture from the formation.
 6540. The method ofclaim 6539, removing a fluid from the formation through a productionwell.
 6541. The method of claim 6539, further comprising removing aliquid through a production well.
 6542. The method of claim 6539,further comprising removing water through a production well.
 6543. Themethod of claim 6539, further comprising removing a fluid through aproduction well prior to providing heat to the formation.
 6544. Themethod of claim 6539, further comprising removing water from theformation through a production well prior to providing heat to theformation.
 6545. The method of claim 6539, further comprising removingthe fluid through a production well using a pump.
 6546. The method ofclaim 6539, further comprising removing a fluid through a conduit. 6547.The method of claim 6539, wherein the heat provided from at least oneheater is transferred to the formation substantially by conduction.6548. The method of claim 6539, wherein the mixture is produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6549. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least one portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; controlling the heat from the oneor more heaters such that an average temperature within at least aselected section of the formation is less than about 375° C.; measuringa temperature within a wellbore placed in the formation; and producing amixture from the formation.
 6550. The method of claim 6549, furthercomprising measuring the temperature using a moveable thermocouple.6551. The method of claim 6549, further comprising measuring thetemperature using an optical fiber assembly.
 6552. The method of claim6549, further comprising measuring the temperature within a productionwell.
 6553. The method of claim 6549, further comprising measuring thetemperature within a heater well.
 6554. The method of claim 6549,further comprising measuring the temperature within a monitoring well.6555. The method of claim 6549, further comprising providing a pressurewave from a pressure wave source into the wellbore, wherein the wellborecomprises a plurality of discontinuities along a length of the wellbore,measuring a reflection signal of the pressure wave, and using thereflection signal to assess at least one temperature between at leasttwo discontinuities.
 6556. The method of claim 6549, further comprisingassessing an average temperature in the formation using one or moretemperatures measured within at least one wellbore.
 6557. The method ofclaim 6549, wherein the heat provided from at least one heater istransferred to the formation substantially by conduction.
 6558. Themethod of claim 6549, wherein the mixture is produced from the formationwhen a partial pressure of hydrogen in at least a portion the formationis at least about 0.5 bars absolute.
 6559. An in situ method ofmeasuring assessing a temperature within a wellbore in a hydrocarboncontaining formation, comprising: providing a pressure wave from apressure wave source into the wellbore, wherein the wellbore comprises aplurality of discontinuities along a length of the wellbore; measuring areflection signal of the pressure wave; and using the reflection signalto assess at least one temperature between at least two discontinuities.6560. The method of claim 6559, wherein the plurality of discontinuitiesare placed along a length of a conduit placed in the wellbore.
 6561. Themethod of claim 6560, wherein the pressure wave is propagated through awall of the conduit.
 6562. The method of claim 6560, wherein theplurality of discontinuities comprises collars placed within theconduit.
 6563. The method of claim 6560, wherein the plurality ofdiscontinuities comprises welds placed within the conduit.
 6564. Themethod of claim 6559, wherein determining the at least one temperaturebetween at least the two discontinuities comprises relating a velocityof the pressure wave between discontinuities to the at least onetemperature.
 6565. The method of claim 6559, further comprisingmeasuring a reference signal of the pressure wave within the wellbore atan ambient temperature.
 6566. The method of claim 6559, furthercomprising measuring a reference signal of the pressure wave within thewellbore at an ambient temperature, and then determining the at leastone temperature between at least the two discontinuities by comparingthe measured signal to the reference signal.
 6567. The method of claim6559, wherein the at least one temperature is a temperature of a gasbetween at least the two discontinuities.
 6568. The method of claim6559, wherein the wellbore comprises a production well.
 6569. The methodof claim 6559, wherein the wellbore comprises a heater well.
 6570. Themethod of claim 6559, wherein the wellbore comprises a monitoring well.6571. The method of claim 6559, wherein the pressure wave sourcecomprises a solenoid valve.
 6572. The method of claim 6559, wherein thepressure wave source comprises an explosive device.
 6573. The method ofclaim 6559, wherein the pressure wave source comprises a sound device.6574. The method of claim 6559, wherein the pressure wave is propagatedthrough the wellbore.
 6575. The method of claim 6559, wherein theplurality of discontinuities have a spacing between each discontinuityof about 5 m.
 6576. The method of claim 6559, further comprisingrepeatedly providing the pressure wave into the wellbore at a selectedfrequency and continuously measuring the reflected signal to increase asignal-to-noise ratio of the reflected signal.
 6577. The method of claim6559, further comprising providing heat from one or more heaters to aportion of the formation.
 6578. The method of claim 6559, furthercomprising pyrolyzing at least some hydrocarbons within a portion of theformation.
 6579. The method of claim 6559, further comprising generatingsynthesis gas in at least a portion of the formation.
 6580. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least one portion of theformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation; controlling the heat from the oneor more heaters such that an average temperature within at least amajority of the selected section of the formation is less than about375° C.; and producing a mixture from the formation through a heaterwell.
 6581. The method of claim 6580, wherein producing the mixturethrough the heater well increases a production rate of the mixture fromthe formation.
 6582. The method of claim 6580, further comprisingproviding heat using at least 2 heaters.
 6583. The method of claim 6580,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons with the selected section of the formation.6584. The method of claim 6580, wherein the one or more heaters comprisea pattern of heaters in a formation, and wherein superposition of heatfrom the pattern of heaters pyrolyzes at least some hydrocarbons withthe selected section of the formation.
 6585. The method of claim 6580,wherein heating of a majority of selected section is controlled suchthat a temperature of the majority of the selected section is less thanabout 375° C.
 6586. The method of claim 6580, wherein the heat providedfrom at least one heater is transferred to the formation substantiallyby conduction.
 6587. The method of claim 6580, wherein the mixture isproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6588.A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heaters to at least oneportion of the formation; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; wherein heating isprovided from at least a first heater and at least a second heater,wherein the first heater has a first heating cost and the second heaterhas a second heating cost; controlling a heating rate of at least aportion of the selected section to preferentially use the first heaterwhen the first heating cost is less than the second heating cost; andcontrolling the heat from the one or more heaters to pyrolyze at leastsome hydrocarbon in the selected section of the formation.
 6589. Themethod of claim 6588, further comprising controlling the heating ratesuch that a temperature within at least a majority of the selectedsection of the formation is less than about 375° C.
 6590. The method ofclaim 6588, further comprising providing heat using at least 2 heaters.6591. The method of claim 6588, wherein the one or more heaters compriseat least two heaters, and wherein superposition of heat from at leastthe two heaters pyrolyzes at least some hydrocarbons with the selectedsection of the formation.
 6592. The method of claim 6588, wherein theone or more heaters comprise a pattern of heaters in a formation, andwherein superposition of heat from the pattern of heaters pyrolyzes atleast some hydrocarbons with the selected section of the formation.6593. The method of claim 6588, further comprising controlling theheating to preferentially use the second heater when the second heatingcost is less than the first heating cost.
 6594. The method of claim6588, further comprising producing a mixture from the formation. 6595.The method of claim 6588, wherein heating of a majority of selectedsection is controlled such that a temperature of the majority of theselected section is less than about 375° C.
 6596. The method of claim6588, wherein the heat provided from at least one heater is transferredto the formation substantially by conduction.
 6597. The method of claim6588, further comprising producing a mixture from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6598. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heaters to at least one portion of the formation; allowing the heatto transfer from the one or more heaters to a selected section of theformation; wherein heating is provided from at least a first heater andat least a second heater, wherein the first heater has a first heatingcost and the second heater has a second heating cost; controlling aheating rate of at least a portion of the selected section such that acost associated with heating the selected section is minimized; andcontrolling the heat from the one or more heaters to pyrolyze at leastsome hydrocarbon in at least a portion of the selected section of theformation.
 6599. The method of claim 6598, wherein the heating rate isvaried within a day depending on a cost associated with heating atvarious times in the day.
 6600. The method of claim 6598, furthercomprising controlling the heating rate such that a temperature withinat least a majority of the selected section of the formation is lessthan about 375° C.
 6601. The method of claim 6598, further comprisingproviding heat using at least 2 heaters.
 6602. The method of claim 6598,wherein the one or more heaters comprise at least two heaters, andwherein superposition of heat from at least the two heaters pyrolyzes atleast some hydrocarbons with the selected section of the formation.6603. The method of claim 6598, wherein the one or more heaters comprisea pattern of heaters in a formation, and wherein superposition of heatfrom the pattern of heaters pyrolyzes at least some hydrocarbons withthe selected section of the formation.
 6604. The method of claim 6598,further comprising producing a mixture from the formation.
 6605. Themethod of claim 6598, wherein heating of a majority of selected sectionis controlled such that a temperature of the majority of the selectedsection is less than about 375° C.
 6606. The method of claim 6598,wherein the heat provided from at least one heater is transferred to theformation substantially by conduction.
 6607. The method of claim 6598,further comprising producing a mixture from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6608. A method for controlling an in situsystem of treating a hydrocarbon containing formation, comprising:monitoring at least one acoustic event within the formation using atleast one acoustic detector placed within a wellbore in the formation;recording at least one acoustic event with an acoustic monitoringsystem; analyzing at least one acoustic event to determine at least oneproperty of the formation; and controlling the in situ system based onthe analysis of the at least one acoustic event.
 6609. The method ofclaim 6608, wherein the at least one acoustic event comprises a seismicevent.
 6610. The method of claim 6608, wherein the method iscontinuously operated.
 6611. The method of claim 6608, wherein theacoustic monitoring system comprises a seismic monitoring system. 6612.The method of claim 6608, further comprising recording the at least oneacoustic event with the acoustic monitoring system.
 6613. The method ofclaim 6608, further comprising monitoring more than one acoustic eventsimultaneously with the acoustic monitoring system.
 6614. The method ofclaim 6608, further comprising monitoring the at least one acousticevent at a sampling rate of about at least once every 0.25 milliseconds.6615. The method of claim 6608, wherein analyzing the at least oneacoustic event comprises interpreting the at least one acoustic event.6616. The method of claim 6608, wherein the at least one property of theformation comprises a location of at least one fracture in theformation.
 6617. The method of claim 6608, wherein the at least oneproperty of the formation comprises an extent of at least one fracturein the formation.
 6618. The method of claim 6608, wherein the at leastone property of the formation comprises an orientation of at least onefracture in the formation.
 6619. The method of claim 6608, wherein theat least one property of the formation comprises a location and anextent of at least one fracture in the formation.
 6620. The method ofclaim 6608, wherein controlling the in situ system comprises modifying atemperature of the in situ system.
 6621. The method of claim 6608,wherein controlling the in situ system comprises modifying a pressure ofthe in situ system.
 6622. The method of claim 6608, wherein the at leastone acoustic detector comprises a geophone.
 6623. The method of claim6608, wherein the at least one acoustic detector comprises a hydrophone.6624. The method of claim 6608, further comprising providing heat to atleast a portion of the formation.
 6625. The method of claim 6608,further comprising pyrolyzing hydrocarbons within at least a portion ofthe formation.
 6626. The method of claim 6608, further comprisingproviding heat from one or more heaters to a portion of the formation.6627. The method of claim 6608, further comprising pyrolyzing at leastsome hydrocarbons within a portion of the formation.
 6628. The method ofclaim 6608, further comprising generating synthesis gas in at least aportion of the formation.
 6629. A method of predicting characteristicsof a formation fluid produced from an in situ process, wherein the insitu process is used for treating a hydrocarbon containing formation,comprising: determining an isothermal experimental temperature that canbe used when treating a sample of the formation, wherein the isothermalexperimental temperature is correlated to a selected in situ heatingrate for the formation; and treating a sample of the formation at thedetermined isothermal experimental temperature, wherein the experimentis used to assess at least one product characteristic of the formationfluid produced from the formation for the selected heating rate. 6630.The method of claim 6629, further comprising determining the at leastone product characteristic at a selected pressure.
 6631. The method ofclaim 6629, further comprising modifying the selected heating rate sothat at least one desired product characteristic of the formation fluidis obtained.
 6632. The method of claim 6629, further comprising using aselected well spacing in the formation to determine the selected heatingrate.
 6633. The method of claim 6629, further comprising using aselected heat input into the formation to determine the selected heatingrate.
 6634. The method of claim 6629, further comprising using at leastone property of the formation to determine the selected heating rate.6635. The method of claim 6629, further comprising selecting a desiredheating rate such that at least one desired product characteristic ofthe formation fluid is obtained.
 6636. The method of claim 6629, furthercomprising determining the isothermal temperature using an equation thatestimates a temperature in which a selected amount of hydrocarbons inthe formation are converted.
 6637. The method of claim 6629, wherein theselected heating rate is less than about 1° C. per day.
 6638. The methodof claim 6629, wherein the sample is treated in an insulated vessel.6639. The method of claim 6629, wherein at least one assessed producedcharacteristic is used to design at least one surface processing system,wherein the surface processing system is used to treat produced fluidson the surface.
 6640. The method of claim 6629, wherein the formation istreated using a heating rate of about the selected heating rate. 6641.The method of claim 6629, further comprising using at least one productcharacteristic to assess a pressure to be maintained in the formationduring treatment.
 6642. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least one portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;adding hydrogen to the selected section after a temperature of theselected section is at least about 270° C.; and producing a mixture fromthe formation.
 6643. The method of claim 6642, wherein the temperatureof the selected section is at least about 290° C.
 6644. The method ofclaim 6642, wherein the temperature of the selected section is at leastabout 320° C.
 6645. The method of claim 6642, wherein the temperature ofthe selected section is less than about 375° C.
 6646. The method ofclaim 6642, wherein the temperature of the selected section is less thanabout 400° C.
 6647. The method of claim 6642, wherein the heat providedfrom at least one heater is transferred to the formation substantiallyby conduction.
 6648. The method of claim 6642, wherein the mixture isproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6649.A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heaters to at least oneportion of the formation; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; and controlling atemperature of a majority of the selected section by selectively addinghydrogen to the formation.
 6650. The method of claim 6649, furthercomprising controlling the temperature such that the temperature is lessthan about 375° C.
 6651. The method of claim 6649, further comprisingcontrolling the temperature such that the temperature is less than about400° C.
 6652. The method of claim 6649, further comprising controlling aheating rate such that the temperature is less than about 375° C. 6653.The method of claim 6649, wherein the one or more heaters comprise apattern of heaters in a formation, and wherein superposition of heatfrom the pattern of heaters pyrolyzes at least some hydrocarbons withthe selected section of the formation.
 6654. The method of claim 6649,further comprising producing a mixture from the formation.
 6655. Themethod of claim 6649, wherein the heat provided from at least one heateris transferred to the formation substantially by conduction.
 6656. Themethod of claim 6649, further comprising producing a mixture from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6657. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least the portion to aselected section of the formation; and producing fluids from theformation wherein at least a portion of the produced fluids have beenheated by the heat provided by one or more of the heaters, and whereinat least a portion of the produced fluids are produced at a temperaturegreater than about 200° C.
 6658. The method of claim 6657, wherein atleast a portion of the produced fluids are produced at a temperaturegreater than about 250° C.
 6659. The method of claim 6657, wherein atleast a portion of the produced fluids are produced at a temperaturegreater than about 300° C.
 6660. The method of claim 6657, furthercomprising varying the heat provided to the one or more heaters to varyheat in at least a portion of the produced fluids.
 6661. The method ofclaim 6657, wherein the produced fluids are produced from a wellcomprising at least one of the heaters, and further comprising varyingthe heat provided to the one or more heaters to vary heat in at least aportion of the produced fluids.
 6662. The method of claim 6657, furthercomprising providing at least a portion of the produced fluids to ahydrotreating unit.
 6663. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit, and further comprising varying the heat provided to the one ormore heaters to vary heat in at least a portion of the produced fluidsprovided to the hydrotreating unit.
 6664. The method of claim 6657,further comprising providing at least a portion of the produced fluidsto a hydrotreating unit, and using heat in the produced fluids whenhydrotreating at least a portion of the produced fluids.
 6665. Themethod of claim 6657, further comprising providing at least a portion ofthe produced fluids to a hydrotreating unit, and hydrotreating at leasta portion of the produced fluids without using a surface heater to heatproduced fluids.
 6666. The method of claim 6657, further comprising:providing at least a portion of the produced fluids to a hydrotreatingunit; and hydrotreating at least a portion of the produced fluids;wherein at least 50% of heat used for hydrotreating is provided by heatin the produced fluids.
 6667. The method of claim 6657, furthercomprising providing at least a portion of the produced fluids to ahydrotreating unit, wherein at least a portion of the produced fluidsare provided to the hydrotreating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6668. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit, wherein at least a portion of the produced fluids are provided tothe hydrotreating unit via a heated conduit.
 6669. The method of claim6657, further comprising providing at least a portion of the producedfluids to a hydrotreating unit, wherein the produced fluids are producedat a wellhead, and wherein at least a portion of the produced fluids areprovided to the hydrotreating unit at a temperature that is within about50° C. of the temperature of the produced fluids at the wellhead. 6670.The method of claim 6657, further comprising hydrotreating at least aportion of the produced fluids such that the volume of hydrotreatedproduced fluids is about 4% greater than a volume of the producedfluids.
 6671. The method of claim 6657, further comprising providing atleast a portion of the produced fluids to a hydrotreating unit, whereinthe produced fluids comprise molecular hydrogen, and using the molecularhydrogen in the produced fluids to hydrotreat at least a portion of theproduced fluids.
 6672. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to a hydrotreatingunit, wherein the produced fluids comprise molecular hydrogen,hydrotreating at least a portion of the produced fluids, and wherein atleast 50% of molecular hydrogen used for hydrotreating is provided bythe molecular hydrogen in the produced fluids.
 6673. The method of claim6657, wherein the produced fluids comprise molecular hydrogen,separating at least a portion of the molecular hydrogen from theproduced fluids, and providing at least a portion of the separatedmolecular hydrogen to a surface treatment unit.
 6674. The method ofclaim 6657, wherein the produced fluids comprise molecular hydrogen,separating at least a portion of the molecular hydrogen from theproduced fluids, and providing at least a portion of the separatedmolecular hydrogen to an in situ treatment area.
 6675. The method ofclaim 6657, further comprising providing a portion of the producedfluids to an olefin generating unit.
 6676. The method of claim 6657,further comprising providing a portion of the produced fluids to a steamcracking unit.
 6677. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit, and further comprising varying heat provided to the oneor more heaters to vary the heat in at least a portion of the producedfluids provided to the olefin generating unit.
 6678. The method of claim6657, further comprising providing at least a portion of the producedfluids to an olefin generating unit, and using heat in the producedfluids when generating olefins from at least a portion of the producedfluids.
 6679. The method of claim 6657, further comprising providing atleast a portion of the produced fluids to an olefin generating unit, andgenerating olefins from at least a portion of the produced fluidswithout using a surface heater to heat produced fluids.
 6680. The methodof claim 6657, further comprising providing at least a portion of theproduced fluids to an olefin generating unit, and generating olefinsfrom at least a portion of the produced fluids, and wherein at least 50%of the heat used for generating olefins is provided by heat in theproduced fluids.
 6681. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6682. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via a heated conduit.
 6683. Themethod of claim 6657, further comprising providing at least a portion ofthe produced fluids to an olefin generating unit, wherein the producedfluids are produced at a wellhead, and wherein at least a portion of theproduced fluids are provided to the olefin generating unit at atemperature that is within about 50° C. of the temperature of theproduced fluids at the wellhead.
 6684. The method of claim 6657, furthercomprising removing heat from the produced fluids in a heat exchanger.6685. The method of claim 6657, further comprising separating theproduced fluids into two or more streams comprising at least a syntheticcondensate stream, and a non-condensable fluid stream.
 6686. The methodof claim 6657, further comprising providing at least a portion of theproduced fluids to a separating unit, and separating at least a portionof the produced fluids into two or more streams.
 6687. The method ofclaim 6657, further comprising providing at least a portion of theproduced fluids to a separating unit, and separating at least a portionof the produced fluids into two or more streams, and further comprisingseparating at least one of such streams into two or more substreams.6688. The method of claim 6657, further comprising providing at least aportion of the produced fluids to a separating unit, and separating atleast a portion of the produced fluids into three or more streams, andwherein such streams comprise at least a top stream, a bottom stream,and a middle stream.
 6689. The method of claim 6657, further comprisingproviding at least a portion of the produced fluids to a separatingunit, and further comprising varying heat provided to the one or moreheaters to vary the heat in at least a portion of the produced fluidsprovided to the separating unit.
 6690. The method of claim 6657, furthercomprising providing at least a portion of the produced fluids to aseparating unit, and using heat in the produced fluids when separatingat least a portion of the produced fluids.
 6691. The method of claim6657, further comprising providing at least a portion of the producedfluids to a separating unit, and separating at least a portion of theproduced fluids without using a surface heater to heat produced fluids.6692. The method of claim 6657, further comprising providing at least aportion of the produced fluids to a separating unit, and separating atleast a portion of the produced fluids, and wherein at least 50% of theheat used for separating is provided by heat in the produced fluids.6693. The method of claim 6657, further comprising providing at least aportion of the produced fluids to a separating unit wherein at least aportion of the produced fluids are provided to the separating unit viaan insulated conduit, and wherein the insulated conduit is insulated toinhibit heat loss from the produced fluids.
 6694. The method of claim6657, further comprising providing at least a portion of the producedfluids to a separating unit wherein at least a portion of the producedfluids are provided to the separating unit via a heated conduit. 6695.The method of claim 6657, further comprising providing at least aportion of the produced fluids to a separating unit, wherein theproduced fluids are produced at a wellhead, and wherein at least aportion of the produced fluids are provided to the separating unit at atemperature that is within about 50° C. of the temperature of theproduced fluids at the wellhead.
 6696. The method of claim 6657, furthercomprising providing at least a portion of the produced fluids to aseparating unit, and separating at least a portion of the producedfluids into four or more streams, and wherein such streams comprise atleast a top stream, a bottoms stream, and at least two middle streamswherein one of the middle streams is heavier than the other middlestream.
 6697. The method of claim 6657, further comprising providing atleast a portion of the produced fluids to a separating unit, andseparating at least a portion of the produced fluids into five or morestreams, and wherein such streams comprise at least a top stream, abottoms stream, a naphtha stream, diesel stream, and a jet fuel stream.6698. The method of claim 6657, further comprising providing at least aportion of the produced fluids to a distillation column, and using heatin the produced fluids when distilling at least a portion of theproduced fluids.
 6699. The method of claim 6657, wherein the producedfluids comprise pyrolyzation fluids.
 6700. The method of claim 6657,wherein the produced fluids comprise carbon dioxide, and furthercomprising separating at least a portion of the carbon dioxide from theproduced fluids.
 6701. The method of claim 6657, wherein the producedfluids comprise carbon dioxide, and further comprising separating atleast a portion of the carbon dioxide from the produced fluids, andutilizing at least some carbon dioxide in one or more treatmentprocesses.
 6702. The method of claim 6657, wherein the produced fluidscomprise molecular hydrogen and wherein the molecular hydrogen is usedwhen treating the produced fluids.
 6703. The method of claim 6657,wherein the produced fluids comprise steam and wherein the steam is usedwhen treating the produced fluids.
 6704. The method of claim 6657,wherein the heat provided from at least one heater is transferred to theformation substantially by conduction.
 6705. The method of claim 6657,wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6706. A method of converting formation fluidsinto olefins, comprising: converting formation fluids into olefins,wherein the formation fluids are obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from one or more heaters to a selected section of theformation such that at least some hydrocarbons in the formation arepyrolyzed; and producing formation fluids from the formation.
 6707. Themethod of claim 6706, wherein the produced fluids comprise steam. 6708.The method of claim 6706, wherein the produced fluids comprise steam andwherein the steam in the produced fluids comprises at least a portion ofsteam used in the olefin generating unit.
 6709. The method of claim6706, further comprising providing at least a portion of the producedfluids to an olefin generating unit.
 6710. The method of claim 6706,further comprising providing at least a portion of the produced fluidsto a steam cracking unit.
 6711. The method of claim 6706, whereinolefins comprise ethylene.
 6712. The method of claim 6706, whereinolefins comprise propylene.
 6713. The method of claim 6706, furthercomprising separating liquids from the produced fluids, and thenseparating olefin generating compounds from the produced fluids, andthen providing at least a portion of the olefin generating compounds toan olefin generating unit.
 6714. The method of claim 6706, wherein theproduced fluids comprise molecular hydrogen, and further comprisingremoving at least a portion of the molecular hydrogen from the producedfluids prior to using the produced fluids to produce olefins.
 6715. Themethod of claim 6706, wherein the produced fluids comprise molecularhydrogen, and further comprising separating at least a portion of themolecular hydrogen from the produced fluids, and utilizing at least aportion of the separated molecular hydrogen in one or more treatmentprocesses.
 6716. The method of claim 6706, wherein the produced fluidscomprise molecular hydrogen, and further comprising removing at least aportion of the molecular hydrogen from the produced fluids using ahydrogen removal unit prior to using the produced fluids to produceolefins.
 6717. The method of claim 6706, wherein the produced fluidscomprises molecular hydrogen, and further comprising removing at least aportion of the molecular hydrogen from the produced fluids using amembrane prior to using the produced fluids to produce olefins. 6718.The method of claim 6706, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to one or more hydrotreating units.6719. The method of claim 6706, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to an in situ treatment area. 6720.The method of claim 6706, further comprising generating molecularhydrogen during production of olefins, and providing at least a portionof the generated molecular hydrogen to one or more fuel cells.
 6721. Themethod of claim 6706, further comprising generating molecular hydrogenduring production of olefins, and using at least a portion of thegenerated molecular hydrogen to hydrotreat pyrolysis liquids generatedin the olefin generation plant.
 6722. The method of claim 6706, whereinthe produced fluids are at least 200° C., and further comprising usingheat in the produced fluids to produce olefins.
 6723. The method ofclaim 6706, further comprising providing at least a portion of theproduced fluids to a hydrotreating unit, wherein the produced fluids areproduced at a wellhead, and wherein at least a portion of the producedfluids are provided to the olefins generating unit at a temperature thatis within about 50° C. of the temperature of the produced fluids at thewellhead.
 6724. The method of claim 6706, wherein the produced fluidscan be used to make olefins without substantial hydrotreating of theproduced fluids.
 6725. The method of claim 6706, further comprisingseparating liquids from the produced fluids, and then using at least aportion of the produced fluids to produce olefins.
 6726. The method ofclaim 6706, further comprising controlling a fluid pressure within atleast a portion of the formation to enhance production of olefingenerating compounds in the produced fluids.
 6727. The method of claim6706, further comprising controlling a temperature within at least aportion of the formation to enhance production of olefin generatingcompounds in the produced fluids.
 6728. The method of claim 6706,further comprising controlling a temperature profile within at least aportion of the formation to enhance production of olefin generatingcompounds in the produced fluids.
 6729. The method of claim 6706,further comprising controlling a heating rate within at least a portionof the formation to enhance production of olefin generating compounds inthe produced fluids.
 6730. The method of claim 6706, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit, and further comprising varying heat provided to the oneor more heaters to vary the heat in at least a portion of the producedfluids provided to the olefin generating unit.
 6731. The method of claim6706, further comprising providing at least a portion of the producedfluids to an olefin generating unit, and using heat in the producedfluids when generating olefins from at least a portion of the producedfluids.
 6732. The method of claim 6706, wherein the produced fluidscomprise steam, and further comprising providing at least a portion ofthe produced fluids to an olefin generating unit, and using steam in theproduced fluids when generating olefins from at least a portion of theproduced fluids.
 6733. The method of claim 6706, wherein the producedfluids comprise steam, and further comprising providing at least aportion of the produced fluids to an olefin generating unit, generatingolefins from at least a portion of the produced fluids, and wherein atleast some steam used for generating olefins is provided by the steam inthe produced fluids.
 6734. The method of claim 6706, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6735. The method of claim 6706, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via a heated conduit.
 6736. Themethod of claim 6706, further comprising separating at least a portionof the produced fluids into one or more fractions wherein the one ormore fractions comprise a naphtha fraction, and further comprisingproviding the naphtha fraction to an olefin generating unit.
 6737. Themethod of claim 6706, further comprising separating at least a portionof the produced fluids into one or more fractions wherein the one ormore fractions comprise a olefin generating fraction wherein the olefingenerating fraction comprises hydrocarbons having a carbon numbergreater than about 1 and a carbon number less than about 8, and furthercomprising providing the olefin generating fraction to a olefingenerating unit.
 6738. The method of claim 6706, further comprisingseparating at least a portion of the produced fluids into one or morefractions wherein the one or more fractions comprise an olefingenerating fraction wherein the olefin generating fraction compriseshydrocarbons having a carbon number greater than about 1 and a carbonnumber less than about 6, and further comprising providing the olefingenerating fraction to a olefin generating unit.
 6739. The method ofclaim 6706, further comprising providing at least the portion of theproduced fluids to a component removal unit such that at least onecomponent stream and a reduced component fluid stream are formed, andthen providing the reduced component fluid stream to an olefingenerating unit.
 6740. The method of claim 6739, wherein the componentcomprises a metal.
 6741. The method of claim 6739, wherein the componentcomprises arsenic.
 6742. The method of claim 6739, wherein the componentcomprises mercury.
 6743. The method of claim 6739, wherein the componentcomprises lead.
 6744. The method of claim 6706, further comprisingproviding at least the portion of the produced fluids to a componentremoval unit such that at least one component stream and a reducedcomponent fluid stream are formed, then providing the reduced componentfluid stream to a molecular hydrogen separating unit such that amolecular hydrogen stream and a reduced hydrogen fluid stream areformed, then providing the molecular hydrogen stream to a hydrotreatingunit, and then providing the reduced hydrogen produced fluid stream toan olefin generating unit.
 6745. The method of claim 6706, wherein theproduced fluids comprise molecular hydrogen and wherein the molecularhydrogen is used when treating the produced fluids.
 6746. The method ofclaim 6706, wherein the produced fluids comprise steam and wherein thesteam is used when treating the produced fluids.
 6747. The method ofclaim 6706, further comprising providing at least a portion of theproduced fluids to an olefin generating unit, and using heat in theproduced fluids when generating olefins from at least a portion of theproduced fluids.
 6748. The method of claim 6706, wherein the producedfluids comprise steam, and further comprising providing at least aportion of the produced fluids to an olefin generating unit, and usingsteam in the produced fluids when generating olefins from at least aportion of the produced fluids.
 6749. The method of claim 6706, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit wherein at least a portion of the produced fluidsare provided to the olefin generating unit via an insulated conduit, andwherein the insulated conduit is insulated to inhibit heat loss from theproduced fluids.
 6750. The method of claim 6706, further comprisingproviding at least a portion of the produced fluids to an olefingenerating unit wherein at least a portion of the produced fluids areprovided to the olefin generating unit via a heated conduit.
 6751. Themethod of claim 6706, wherein the heat provided from at least one heateris transferred to the formation substantially by conduction.
 6752. Themethod of claim 6706, wherein the formation fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6753. A method ofseparating olefins from fluids produced from a hydrocarbon containingformation, comprising: separating olefins from the produced fluids,wherein the produced fluids are obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from at least one or more heaters to a selected section ofthe formation; and producing fluids from the formation, wherein theproduced fluids comprise olefins.
 6754. The method of claim 6753,wherein olefins comprise ethylene.
 6755. The method of claim 6753,wherein olefins comprise propylene.
 6756. The method of claim 6753,further comprising separating liquids from the produced fluids. 6757.The method of claim 6753, wherein the produced fluids comprise molecularhydrogen, and further comprising separating at least a portion of themolecular hydrogen from the produced fluids, and utilizing at least aportion of the separated molecular hydrogen in one or more treatmentprocesses.
 6758. The method of claim 6753, wherein the produced fluidscomprise molecular hydrogen, and further comprising removing at least aportion of the molecular hydrogen from the produced fluids using ahydrogen removal unit.
 6759. The method of claim 6753, wherein theproduced fluids comprises molecular hydrogen, and further comprisingremoving at least a portion of the molecular hydrogen from the producedfluids using a membrane.
 6760. The method of claim 6753, furthercomprising controlling a fluid pressure within at least a portion of theformation to enhance production of olefins in the produced fluids. 6761.The method of claim 6753, further comprising controlling a temperaturewithin at least a portion of the formation to enhance production ofolefins in the produced fluids.
 6762. The method of claim 6753, furthercomprising controlling a temperature profile within at least a portionof the formation to enhance production of olefins in the producedfluids.
 6763. The method of claim 6753, further comprising controlling aheating rate within at least a portion of the formation to enhanceproduction of olefins in the produced fluids.
 6764. The method of claim6753, further comprising providing at least a portion of the producedfluids to an olefin generating unit, and further comprising varying heatprovided to the one or more heaters to vary the heat in at least aportion of the produced fluids provided to the olefin generating unit.6765. The method of claim 6753, further comprising providing at least aportion of the produced fluids to an olefin generating unit, and usingheat in the produced fluids when generating olefins from at least aportion of the produced fluids.
 6766. The method of claim 6753, whereinthe produced fluids comprise steam, and further comprising providing atleast a portion of the produced fluids to an olefin generating unit, andusing steam in the produced fluids when generating olefins from at leasta portion of the produced fluids.
 6767. The method of claim 6753,further comprising providing at least a portion of the produced fluidsto an olefin generating unit wherein at least a portion of the producedfluids are provided to the olefin generating unit via an insulatedconduit, and wherein the insulated conduit is insulated to inhibit heatloss from the produced fluids.
 6768. The method of claim 6753, furthercomprising providing at least a portion of the produced fluids to anolefin generating unit wherein at least a portion of the produced fluidsare provided to the olefin generating unit via a heated conduit. 6769.The method of claim 6753, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an olefin generating unit.6770. The method of claim 6753, further comprising separating at least aportion of the produced fluids into one or more fractions wherein theone or more fractions comprise a olefin generating fraction wherein theolefin generating fraction comprises hydrocarbons having a carbon numbergreater than about 1 and a carbon number less than about 8, and furthercomprising providing the olefin generating fraction to a olefingenerating unit.
 6771. The method of claim 6753, further comprisingseparating at least a portion of the produced fluids into one or morefractions wherein the one or more fractions comprise an olefingenerating fraction wherein the olefin generating fraction compriseshydrocarbons having a carbon number greater than about 1 and a carbonnumber less than about 6, and further comprising providing the olefingenerating fraction to a olefin generating unit.
 6772. The method ofclaim 6753, further comprising providing at least the portion of theproduced fluids to a component removal unit such that at least onecomponent stream and a reduced component fluid stream are formed, andthen providing the reduced component fluid stream to an olefingenerating unit.
 6773. The method of claim 6772, wherein the componentcomprises a metal.
 6774. The method of claim 6772, wherein the componentcomprises arsenic.
 6775. The method of claim 6772, wherein the componentcomprises mercury.
 6776. The method of claim 6772, wherein the componentcomprises lead.
 6777. The method of claim 6753, further comprisingproviding at least the portion of the produced fluids to a componentremoval unit such that at least one component stream and a reducedcomponent fluid stream are formed, then providing the reduced componentfluid stream to a molecular hydrogen separating unit such that amolecular hydrogen stream and a reduced hydrogen fluid stream areformed, then providing the molecular hydrogen stream to a hydrotreatingunit, and then providing the reduced hydrogen produced fluid stream toan olefin generating unit.
 6778. The method of claim 6753, furthercomprising controlling a temperature gradient within at least a portionof the formation to enhance production of olefins in the producedfluids.
 6779. The method of claim 6753, further comprising controlling afluid pressure within at least a portion of the formation to enhanceproduction of olefins in the produced fluids.
 6780. The method of claim6753, further comprising controlling a temperature within at least aportion of the formation to enhance production of olefins in theproduced fluids.
 6781. The method of claim 6753, further comprisingcontrolling a heating rate within at least a portion of the formation toenhance production of olefins in the produced fluids.
 6782. The methodof claim 6753, further comprising separating the olefins from theproduced fluids such that an amount of molecular hydrogen utilized inone or more downstream hydrotreating units decreases.
 6783. The methodof claim 6753, further comprising removing at least a portion of theolefins prior to hydrotreating produced fluids.
 6784. A method ofenhancing phenol production from an in situ hydrocarbon containingformation, comprising: controlling at least one condition within atleast a portion of the formation to enhance production of phenols information fluid, wherein the formation fluid is obtained by: providingheat from one or more heaters to at least the portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation; and producing formation fluids fromthe formation.
 6785. The method of claim 6784, further comprisingseparating at least a portion of the phenols from the produced fluids.6786. The method of claim 6784, wherein controlling at least onecondition in the formation comprises controlling a fluid pressure withinat least a portion of the formation.
 6787. The method of claim 6784,wherein controlling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6788. The method of claim 6784, wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6789. The method of claim6784, wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6790. The method of claim 6784, wherein the at least onecondition in the formation is controlled such that an average carbonnumber of the produced fluids is lowered.
 6791. The method of claim6784, further comprising separating at least a portion of the producedfluids into a phenols fraction at a wellhead using condensation. 6792.The method of claim 6784, further comprising separating at least aportion of the produced fluids into a phenols fraction at a wellheadusing fractionation.
 6793. The method of claim 6784, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an extraction unit, andseparating at least some phenols from the naphtha fraction.
 6794. Themethod of claim 6784, further comprising separating the produced fluidsinto a gas stream and a liquid stream, separating the liquid stream intoa phenols fraction and a hydrocarbon containing fraction, and providingthe hydrocarbon containing fraction to a pipeline.
 6795. The method ofclaim 6784, further comprising separating the produced fluids into oneor more fractions wherein the one or more fractions comprise a phenolsfraction, and further comprising providing the phenols fraction to anextraction unit, and separating at least some phenols from the phenolsfluids.
 6796. The method of claim 6784, further comprising separatingthe phenols from the produced fluids with a water/methanol extractionprocess.
 6797. The method of claim 6784, further comprising separatingthe phenols from the produced fluids such that an amount of molecularhydrogen utilized in one or more downstream hydrotreating unitsdecreases.
 6798. The method of claim 6784, wherein controlling acondition comprises lowering the average carbon number of the producedfluids.
 6799. The method of claim 6784, further comprising removing atleast a portion of the phenols prior to hydrotreating produced fluids.6800. The method of claim 6784, further comprising removing at least aportion of the phenols prior to hydrotreating produced fluids, andwherein removing at least the portion reduces an amount of molecularhydrogen required in a hydrotreating unit.
 6801. The method of claim6784, further comprising reacting at least a portion of the phenols withmolecular hydrogen to form phenol.
 6802. The method of claim 6784,wherein the selected section has been selected for heating using anoxygen content of at least some hydrocarbons in the selected section.6803. The method of claim 6784, wherein the heat provided from at leastone heater is transferred to the formation substantially by conduction.6804. The method of claim 6784, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6805. A method ofcontrolling phenol production from a hydrocarbon containing formation,comprising; converting at least a portion of formation fluid intophenol, wherein the formation fluids in situ are obtained by: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section; and producing formation fluids from the formation.6806. The method of claim 6805, wherein the formation fluids comprisephenols.
 6807. The method of claim 6805, wherein converting at least aportion of formation fluid into phenol comprises reacting at least aportion of the phenols with molecular hydrogen to form phenol.
 6808. Themethod of claim 6805, wherein the heat provided from at least one heateris transferred to the formation substantially by conduction.
 6809. Themethod of claim 6805, wherein the formation fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6810. A method ofseparating phenols from fluids produced from a hydrocarbon containingformation, comprising: separating phenols from the produced fluids,wherein the produced fluids are obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from at least one or more heaters to a selected section ofthe formation; and producing fluids from the formation, wherein theproduced fluids comprise phenols.
 6811. The method of claim 6810,further comprising controlling a fluid pressure within at least aportion of the formation.
 6812. The method of claim 6810, furthercomprising controlling a temperature gradient within at least a portionof the formation.
 6813. The method of claim 6810, further comprisingcontrolling a temperature within at least a portion of the formation.6814. The method of claim 6810, further comprising controlling a heatingrate within at least a portion of the formation.
 6815. The method ofclaim 6810, wherein separating the phenols from the produced fluids,further comprises removing a naphtha fraction from the produced fluids,and separating phenols from the naphtha fraction.
 6816. The method ofclaim 6810, wherein separating the phenols from the produced fluids,further comprises removing a phenols fraction from the produced fluids,and separating at least some phenols from the phenols fraction. 6817.The method of claim 6810, wherein separating the phenols from theproduced fluids, further comprises removing phenols with awater/methanol extraction.
 6818. The method of claim 6810, whereinseparating the phenols from the produced fluids decreases an amount ofmolecular hydrogen utilized in one or more downstream hydrotreatingunits.
 6819. The method of claim 6810, wherein controlling a conditioncomprises lowering the average carbon number of the produced fluids.6820. The method of claim 6810, further comprising removing at least aportion of the phenols prior to hydrotreating produced fluids.
 6821. Themethod of claim 6810, further comprising removing at least a portion ofthe phenols prior to hydrotreating produced fluids, and wherein removingat least the portion reduces an amount of molecular hydrogen required ina hydrotreating unit.
 6822. The method of claim 6810, further comprisingreacting at least a portion of the phenols with molecular hydrogen toform phenol.
 6823. The method of claim 6810, wherein the heat providedfrom at least one heater is transferred to the formation substantiallyby conduction.
 6824. The method of claim 6810, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6825.A method of enhancing phenol production from a hydrocarbon containingformation, comprising: controlling at least one condition within atleast a portion of the formation to enhance production of phenols information fluid, wherein the formation fluid is obtained by: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation; and producing formation fluids fromthe formation.
 6826. The method of claim 6825, further comprisingseparating at least a portion of the phenols from the produced fluids.6827. The method of claim 6825, further comprising controlling at leastone condition in situ such that an average carbon number of the producedfluids is lowered.
 6828. The method of claim 6825, further comprisingcontrolling a temperature gradient within at least a portion of theformation.
 6829. The method of claim 6825, further comprisingcontrolling a fluid pressure within at least a portion of the formation.6830. The method of claim 6825, further comprising controlling atemperature within at least a portion of the formation.
 6831. The methodof claim 6825, further comprising controlling a heating rate within atleast a portion of the formation.
 6832. The method of claim 6825,further comprising separating at least a portion of the produced fluidsinto a phenols fraction at a wellhead using condensation.
 6833. Themethod of claim 6825, further comprising separating at least a portionof the produced fluids into a phenols fraction at a wellhead usingfractionation.
 6834. The method of claim 6825, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a naphtha fraction, and furthercomprising providing the naphtha fraction to an extraction unit, andseparating at least some phenols from the naphtha fraction.
 6835. Themethod of claim 6825, further comprising separating the produced fluidsinto one or more fractions wherein the one or more fractions comprise aphenols fraction, and further comprising providing the phenols fractionto an extraction unit, and separating at least some phenols from thephenols fluids.
 6836. The method of claim 6825, further comprisingseparating the phenols from the produced fluids with a water/methanolextraction process.
 6837. The method of claim 6825, further comprisingseparating the phenols from the produced fluids such that an amount ofmolecular hydrogen utilized in one or more downstream hydrotreatingunits decreases.
 6838. The method of claim 6825, further comprisingremoving at least a portion of the phenols prior to hydrotreatingproduced fluids.
 6839. The method of claim 6825, further comprisingremoving at least a portion of the phenols prior to hydrotreatingproduced fluids, and wherein removing at least the portion reduces anamount of molecular hydrogen required in a hydrotreating unit.
 6840. Themethod of claim 6825, wherein the heat provided from at least one heateris transferred to the formation substantially by conduction.
 6841. Themethod of claim 6825, wherein the formation fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6842. A method ofenhancing BTEX compounds production from a hydrocarbon containingformation, comprising: controlling at least one condition within atleast a portion of the formation to enhance production of BTEX compoundsin formation fluid, wherein the formation fluid is obtained by:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least one or moreheaters to a selected section of the formation; and producing formationfluids from the formation.
 6843. The method of claim 6842, furthercomprising separating at least a portion of the BTEX compounds from theproduced fluids.
 6844. The method of claim 6842, further comprisingseparating at least a portion of the BTEX compounds from the producedfluids via solvent extraction.
 6845. The method of claim 6842, furthercomprising separating at least a portion of the BTEX compounds from theproduced fluids via distillation.
 6846. The method of claim 6842,further comprising separating at least a portion of the BTEX compoundsfrom the produced fluids via condensation.
 6847. The method of claim6842, further comprising separating at least a portion of the BTEXcompounds from the produced fluids such that an amount of molecularhydrogen utilized in one or more downstream hydrotreating unitsdecreases.
 6848. The method of claim 6842, wherein controlling at leastone condition in the formation comprises controlling a fluid pressurewithin at least a portion of the formation.
 6849. The method of claim6842, wherein controlling at least one condition in the formationcomprises controlling a temperature gradient within at least a portionof the formation.
 6850. The method of claim 6842, wherein controlling atleast one condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6851. The method of claim6842, wherein controlling at least one cdndition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6852. The method of claim 6842, further comprising removingat least a portion of the BTEX compounds prior to hydrotreating producedfluids.
 6853. The method of claim 6842, further comprising removing atleast a portion of the phenols prior to hydrotreating produced fluids,and wherein removing at least the portion reduces an amount of molecularhydrogen required in a hydrotreating unit.
 6854. The method of claim6842, wherein the heat provided from at least one heater is transferredto the formation substantially by conduction.
 6855. The method of claim6842, wherein the formation fluids are produced from the formation whena partial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6856. A method of separating BTEXcompounds from formation fluid from a hydrocarbon containing formation,comprising: separating at least a portion of the BTEX compounds from theformation fluid wherein the formation fluid is obtained by: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation; and producing fluids from theformation, wherein the produced fluids comprise BTEX compounds. 6857.The method of claim 6856, further comprising hydrotreating at least aportion of the produced fluids after the BTEX compounds have beenseparated from same.
 6858. The method of claim 6856, wherein separatingat least a portion of the BTEX compounds from the produced fluidscomprises extracting at least the portion of the BTEX compounds from theproduced fluids via solvent extraction.
 6859. The method of claim 6856,wherein separating at least a portion of the BTEX compounds from theproduced fluids comprises distilling at least the portion of the BTEXcompounds from the produced fluids.
 6860. The method of claim 6856,wherein separating at least a portion of the BTEX compounds from theproduced fluids comprises condensing at least the portion of the BTEXcompounds from the produced fluids.
 6861. The method of claim 6856,wherein separating at least a portion of the BTEX compounds from theproduced fluids such that an amount of molecular hydrogen utilized inone or more downstream hydrotreating units decreases.
 6862. The methodof claim 6856, further comprising controlling a fluid pressure within atleast a portion of the formation.
 6863. The method of claim 6856,further comprising controlling a temperature gradient within at least aportion of the formation.
 6864. The method of claim 6856, furthercomprising controlling a temperature within at least a portion of theformation.
 6865. The method of claim 6856, further comprisingcontrolling a heating rate within at least a portion of the formation.6866. The method of claim 6856, wherein separating at least the portionof BTEX compounds from the produced fluids further comprises removing anaphtha fraction from the produced fluids, and separating at least theportion of BTEX compounds from the naphtha fraction.
 6867. The method ofclaim 6856, wherein separating at least the portion of BTEX compoundsfrom the produced fluids, further comprises removing a BTEX fractionfrom the produced fluids, and separating at some BTEX compounds from theBTEX fraction.
 6868. The method of claim 6856, wherein separating atleast the portion of BTEX compounds from the produced fluids decreasesan amount of molecular hydrogen utilized in one or more downstreamhydrotreating units.
 6869. A method of in situ converting at least aportion of formation fluid into BTEX compounds, comprising: in situconverting at least the portion of the formation fluid into BTEXcompounds, wherein the formation fluid are obtained by: providing heatfrom one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation such that at least some hydrocarbonsin the formation are pyrolyzed; and producing formation fluid from theformation.
 6870. The method of claim 6869, further comprising providingat least a portion of the formation fluid to an BTEX generating unit.6871. The method of claim 6869, further comprising providing at least aportion of the formation fluid to a catalytic reforming unit.
 6872. Themethod of claim 6869, further comprising hydrotreating at least some ofthe formation fluid, and then separating the hydrotreated mixture intoone more streams comprising a naphtha stream, and then reforming atleast a portion the naphtha stream to form a reformate comprising BTEXcompounds, and then separating at least a portion of the BTEX compoundsfrom the reformate.
 6873. The method of claim 6869, further comprisinghydrotreating at least some of the formation fluid, and then separatingthe hydrotreated mixture into one more streams comprising a naphthastream, and then reforming at least a portion the naphtha stream to forma molecular hydrogen stream and a reformate comprising BTEX compounds,and then separating at least a portion of the BTEX compounds from thereformate, and then utilizing the molecular hydrogen stream tohydrotreat at least some of the formation fluid.
 6874. The method ofclaim 6869, further comprising hydrotreating the formation fluid, andthen separating the hydrotreated formation fluid into one more streamscomprising a naphtha stream, and then reforming at least a portion thenaphtha stream to form a reformate comprising BTEX compounds, and thenseparating at least a portion of the reformate into two or more streamscomprising a raffinate and a BTEX stream.
 6875. The method of claim6869, wherein the formation fluid is at least 200° C., and furthercomprising using heat in the formation fluid to hydrotreat at least aportion of the formation fluid.
 6876. The method of claim 6869, furthercomprising separating at least a portion of the formation fluid into oneor more fractions wherein the one or more fractions comprise a naphthafraction, and further comprising providing the naphtha fraction to acatalytic reforming unit.
 6877. The method of claim 6869, furthercomprising separating at least a portion of the formation fluid into oneor more fractions wherein the one or more fractions comprise a BTEXcompound generating fraction wherein the BTEX compound generatingfraction comprises hydrocarbons, and further comprising providing theBTEX compound generating fraction to a catalytic reforming unit. 6878.The method of claim 6869, wherein the heat provided from at least oneheater is transferred to the formation substantially by conduction.6879. The method of claim 6869, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6880. A method ofenhancing naphthalene production from a hydrocarbon containingformation, comprising: controlling at least one condition within atleast a portion of the formation to enhance production of naphthalene information fluid, wherein the formation fluid is obtained by: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation; and producing formation fluids fromthe formation.
 6881. The method of claim 6880, further comprisingseparating at least a portion of the naphthalene from the producedfluids.
 6882. The method of claim 6880, wherein controlling at least onecondition in the formation comprises controlling a fluid pressure withinat least a portion of the formation.
 6883. The method of claim 6880,wherein controlling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6884. The method of claim 6880, wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6885. The method of claim6880, wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6886. The method of claim 6880, further comprising separatingthe produced fluids into one or more fractions using distillation. 6887.The method of claim 6880, further comprising separating the producedfluids into one or more fractions using condensation.
 6888. The methodof claim 6880, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some naphthalene from the heart cut. 6889.The method of claim 6880, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a naphthalene fraction, and further comprising providing thenaphthalene fraction to an extraction unit, and separating at least somenaphthalene from the naphthalene fraction.
 6890. The method of claim6880, wherein the heat provided from at least one heater is transferredto the formation substantially by conduction.
 6891. The method of claim6880, wherein the formation fluids are produced from the formation whena partial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6892. A method of separating naphthalenefrom fluids produced from a hydrocarbon containing formation,comprising: separating naphthalene from the produced fluids, wherein theproduced fluids are obtained by: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom at least one or more heaters to a selected section of theformation; and producing fluids from the formation, wherein the producedfluids comprise naphthalene.
 6893. The method of claim 6892, furthercomprising controlling a fluid pressure within at least a portion of theformation.
 6894. The method of claim 6892, further comprisingcontrolling a temperature gradient within at least a portion of theformation.
 6895. The method of claim 6892, further comprisingcontrolling a temperature within at least a portion of the formation.6896. The method of claim 6892, further comprising controlling a heatingrate within at least a portion of the formation.
 6897. The method ofclaim 6892, wherein separating at least some naphthalene from theproduced fluids further comprises separating the produced fluids intoone or more fractions using distillation.
 6898. The method of claim6892, wherein separating at least some naphthalene from the producedfluids further comprises separating the produced fluids into one or morefractions using condensation.
 6899. The method of claim 6892, whereinseparating at least some naphthalene from the produced fluids furthercomprises separating the produced fluids into one or more fractionswherein the one or more fractions comprise a heart cut, and extractingat least a portion of the naphthalene from the heart cut.
 6900. Themethod of claim 6892, wherein separating at least some naphthalene fromthe produced fluids further comprises removing a naphtha fraction fromthe produced fluids, and separating at least a portion of thenaphthalene from the naphtha fraction.
 6901. The method of claim 6892,wherein separating at least some naphthalene from the produced fluidsfurther comprises removing an naphthalene fraction from the producedfluids, and separating at least a portion of the naphthalene from thenaphthalene fraction.
 6902. The method of claim 6892, wherein separatingthe naphthalene from the produced fluids further comprises removingnaphthalene using distillation.
 6903. The method of claim 6892, whereinseparating the naphthalene from the produced fluids further comprisesremoving naphthalene using crystallization.
 6904. The method of claim6892, further comprising removing at least a portion of the naphthaleneprior to hydrotreating produced fluids.
 6905. The method of claim 6892,further comprising removing at least a portion of the phenols prior tohydrotreating produced fluids, and wherein removing at least the portionreduces an amount of molecular hydrogen required in a hydrotreatingunit.
 6906. The method of claim 6892, wherein the heat provided from atleast one heater is transferred to the formation substantially byconduction.
 6907. The method of claim 6892, wherein the formation fluidsare produced from the formation when a partial pressure of hydrogen inat least a portion the formation is at least about 0.5 bars absolute.6908. A method of enhancing anthracene production from a hydrocarboncontaining formation, comprising: controlling at least one conditionwithin at least a portion of the formation to enhance production ofanthracene in formation fluid, wherein the formation fluid is obtainedby: providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least one or moreheaters to a selected section of the formation; and producing formationfluids from the formation.
 6909. The method of claim 6908, furthercomprising separating at least a portion of the anthracene from theproduced fluids.
 6910. The method of claim 6908, wherein controlling atleast one condition in the formation comprises controlling a fluidpressure within at least a portion of the formation.
 6911. The method ofclaim 6908, wherein controlling at least one condition in the formationcomprises controlling a temperature gradient within at least a portionof the formation.
 6912. The method of claim 6908, wherein controlling atleast one condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6913. The method of claim6908, wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6914. The method of claim 6908, further comprising separatingthe produced fluids into one or more fractions using distillation. 6915.The method of claim 6908, further comprising separating the producedfluids into one or more fractions using condensation.
 6916. The methodof claim 6908, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some anthracene from the heart cut. 6917.The method of claim 6908, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a anthracene fraction, and further comprising providing theanthracene fraction to an extraction unit, and separating at least someanthracene from the anthracene fraction.
 6918. The method of claim 6908,wherein the heat provided from at least one heater is transferred to theformation substantially by conduction.
 6919. The method of claim 6908,wherein the formation fluids are produced from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6920. A method of separating anthracenefrom fluids produced from a hydrocarbon containing formation,comprising: separating anthracene from the produced fluids, wherein theproduced fluids are obtained by: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom at least one or more heaters to a selected section of theformation; and producing fluids from the formation, wherein the producedfluids comprise anthracene.
 6921. The method of claim 6920, furthercomprising controlling a fluid pressure within at least a portion of theformation.
 6922. The method of claim 6920, further comprisingcontrolling a temperature gradient within at least a portion of theformation.
 6923. The method of claim 6920, further comprisingcontrolling a temperature within at least a portion of the formation.6924. The method of claim 6920, further comprising controlling a heatingrate within at least a portion of the formation.
 6925. The method ofclaim 6920, wherein separating at least some anthracene from theproduced fluids further comprises separating the produced fluids intoone or more fractions using distillation.
 6926. The method of claim6920, wherein separating at least some anthracene from the producedfluids further comprises separating the produced fluids into one or morefractions using condensation.
 6927. The method of claim 6920, whereinseparating at least some anthracene from the produced fluids furthercomprises separating the produced fluids into one or more fractionswherein the one or more fractions comprise a heart cut, and extractingat least a portion of the anthracene from the heart cut.
 6928. Themethod of claim 6920, wherein separating at least some anthracene fromthe produced fluids further comprises removing a naphtha fraction fromthe produced fluids, and separating at least a portion of the anthracenefrom the naphtha fraction.
 6929. The method of claim 6920, whereinseparating at least some anthracene from the produced fluids furthercomprises removing an anthracene fraction from the produced fluids, andseparating at least a portion of the anthracene from the anthracenefraction.
 6930. The method of claim 6920, wherein separating theanthracene from the produced fluids further comprises removinganthracene using distillation.
 6931. The method of claim 6920, whereinseparating the anthracene from the produced fluids further comprisesremoving anthracene using crystallization.
 6932. The method of claim6920, wherein the heat provided from at least one heater is transferredto the formation substantially by conduction.
 6933. The method of claim6920, wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 6934. A method of separating ammonia fromfluids produced from a hydrocarbon containing formation, comprising:separating at least a portion of the ammonia from the produced fluid,wherein the produced fluids are obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from at least one or more heaters to a selected section ofthe formation; and producing fluids from the formation.
 6935. The methodof claim 6934, wherein the produced fluids are pyrolyzation fluids.6936. The method of claim 6934, wherein separating at least a portion ofthe ammonia from the produced fluids further comprises providing atleast a portion of the produced fluids to a sour water stripper. 6937.The method of claim 6934, wherein separating at least a portion of theammonia from the produced fluids further comprises separating theproduced fluids into one or more fractions, and providing at least aportion of the one or more fractions to a stripping unit.
 6938. Themethod of claim 6934, further comprising using at least a portion of theseparated ammonia to generate ammonium sulfate.
 6939. The method ofclaim 6934, further comprising using at least a portion of the separatedammonia to generate urea.
 6940. The method of claim 6934, wherein theproduced fluids comprise carbon dioxide, and further comprisingseparating the carbon dioxide from the produced fluids, and reacting thecarbon dioxide with at least some ammonia to form urea.
 6941. The methodof claim 6934, wherein the produced fluids comprise hydrogen sulfide,and further comprising separating the hydrogen sulfide from the producedfluids, converting at least some hydrogen sulfide into sulfuric acid,and reacting at lest some sulfuric acid with at lease some ammonia toform ammonium sulfate.
 6942. The method of claim 6934, wherein theproduced fluids further comprise hydrogen sulfide, and furthercomprising separating at least a portion of the hydrogen sulfide fromthe produced fluids, and converting at least some hydrogen sulfide intosulfuric acid.
 6943. The method of claim 6934, further comprisinggenerating ammonium bicarbonate using separated ammonia.
 6944. Themethod of claim 6934, further comprising providing separated ammonia toa fluid comprising carbon dioxide to generate ammonium bicarbonate.6945. The method of claim 6934, further comprising providing separatedammonia to at least some synthesis gas to generate ammonium bicarbonate.6946. The method of claim 6934, wherein the heat provided from at leastone heater is transferred to the formation substantially by conduction.6947. The method of claim 6934, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6948. A method ofgenerating ammonia from fluids produced from a hydrocarbon containingformation, comprising: hydrotreating at least a portion of the producedfluids to generate ammonia, wherein the produced fluids are obtained by:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least one or moreheaters to a selected section of the formation; and producing fluidsfrom the formation.
 6949. The method of claim 6948, wherein the producedfluids are pyrolyzation fluids.
 6950. The method of claim 6948, furthercomprising separating at least a portion of the ammonia from thehydrotreated fluids.
 6951. The method of claim 6948, further comprisingusing at least a portion of the ammonia to generate ammonium sulfate.6952. The method of claim 6948, further comprising using at least aportion of the ammonia to generate urea.
 6953. The method of claim 6948,wherein the produced fluids further comprise carbon dioxide, and furthercomprising separating at least a portion of the carbon dioxide from theproduced fluids, and reacting at least the portion of the carbon dioxidewith at least a portion of ammonia to form urea.
 6954. The method ofclaim 6948, wherein the produced fluids further comprise hydrogensulfide, and further comprising separating at least a portion of thehydrogen sulfide from the produced fluids, converting at least somehydrogen sulfide into sulfuric acid, and reacting at least some sulfuricacid with at least a portion of the ammonia to form ammonium sulfate.6955. The method of claim 6948, wherein the produced fluids furthercomprise hydrogen sulfide, and further comprising separating at least aportion of the hydrogen sulfide from the produced fluids, and convertingat least some hydrogen sulfide into sulfuric acid.
 6956. The method ofclaim 6948, further comprising generating ammonium bicarbonate using atleast a portion of the ammonia.
 6957. The method of claim 6948, furthercomprising providing at least a portion of the ammonia to a fluidcomprising carbon dioxide to generate ammonium bicarbonate.
 6958. Themethod of claim 6948, further comprising providing at least a portion ofthe ammonia to at least some synthesis gas to generate ammoniumbicarbonate.
 6959. The method of claim 6948, wherein the heat providedfrom at least one heater is transferred to the formation substantiallyby conduction.
 6960. The method of claim 6948, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 6961.A method of enhancing pyridines production from a hydrocarbon containingformation, comprising: controlling at least one condition within atleast a portion of the formation to enhance production of pyridines information fluid, wherein the formation fluid is obtained by: providingheat from one or more heaters to at least a portion of the formation;allowing the heat to transfer from at least one or more heaters to aselected section of the formation; and producing formation fluids fromthe formation.
 6962. The method of claim 6961, further comprisingseparating at least a portion of the pyridines from the produced fluids.6963. The method of claim 6961, wherein controlling at least onecondition in the formation comprises controlling a fluid pressure withinat least a portion of the formation.
 6964. The method of claim 6961,wherein controlling at least one condition in the formation comprisescontrolling a temperature gradient within at least a portion of theformation.
 6965. The method of claim 6961, wherein controlling at leastone condition in the formation comprises controlling a temperaturewithin at least a portion of the formation.
 6966. The method of claim6961, wherein controlling at least one condition in the formationcomprises controlling a heating rate within at least a portion of theformation.
 6967. The method of claim 6961, further comprising separatingthe produced fluids into one or more fractions using distillation. 6968.The method of claim 6961, further comprising separating the producedfluids into one or more fractions using condensation.
 6969. The methodof claim 6961, further comprising separating the produced fluids intoone or more fractions wherein the one or more fractions comprise a heartcut, and further comprising providing the heart cut to an extractionunit, and separating at least some pyridines from the heart cut. 6970.The method of claim 6961, further comprising separating the producedfluids into one or more fractions wherein the one or more fractionscomprise a pyridines fraction, and further comprising providing thepyridines fraction to an extraction unit, and separating at least somepyridines from the pyridines fraction.
 6971. The method of claim 6961,wherein the heat provided from at least one heater is transferred to theformation substantially by conduction.
 6972. The method of claim 6961,wherein the formation fluids are produced from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 6973. A method of separating pyridinesfrom fluids produced from a hydrocarbon containing formation,comprising: separating pyridines from the produced fluids, wherein theproduced fluids are obtained by: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom at least one or more heaters to a selected section of theformation; and producing fluids from the formation, wherein the producedfluids comprise pyridines.
 6974. The method of claim 6973, furthercomprising controlling a fluid pressure within at least a portion of theformation.
 6975. The method of claim 6973, further comprisingcontrolling a temperature gradient within at least a portion of theformation.
 6976. The method of claim 6973, further comprisingcontrolling a temperature within at least a portion of the formation.6977. The method of claim 6973, further comprising controlling a heatingrate within at least a portion of the formation.
 6978. The method ofclaim 6973, wherein separating at least some pyridines from the producedfluids further comprises separating the produced fluids into one or morefractions using distillation.
 6979. The method of claim 6973, whereinseparating at least some pyridines from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing condensation.
 6980. The method of claim 6973, wherein separatingat least some pyridines from the produced fluids further comprisesseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and extracting at least aportion of the pyridines from the heart cut.
 6981. The method of claim6973, wherein separating at least some pyridines from the producedfluids further comprises removing a naphtha fraction from the producedfluids, and separating at least a portion of the pyridines from thenaphtha fraction.
 6982. The method of claim 6973, wherein separating atleast some pyridines from the produced fluids further comprises removingan pyridines fraction from the produced fluids, and separating at leasta portion of the pyridines from the pyridines fraction.
 6983. The methodof claim 6973, wherein separating the pyridines from the produced fluidsfurther comprises removing pyridines using distillation.
 6984. Themethod of claim 6973, wherein separating the pyridines from the producedfluids further comprises removing pyridines using crystallization. 6985.The method of claim 6973, wherein the heat provided from at least oneheater is transferred to the formation substantially by conduction.6986. The method of claim 6973, wherein the fluids are produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 6987. A method ofenhancing pyrroles production from a hydrocarbon containing formation,comprising: controlling at least one condition within at least a portionof the formation to enhance production of pyrroles in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from at least one or more heaters to a selected section ofthe formation; and producing formation fluids from the formation. 6988.The method of claim 6987, further comprising separating at least aportion of the pyrroles from the produced fluids.
 6989. The method ofclaim 6987, wherein controlling at least one condition in the formationcomprises controlling a fluid pressure within at least a portion of theformation.
 6990. The method of claim 6987, wherein controlling at leastone condition in the formation comprises controlling a temperaturegradient within at least a portion of the formation.
 6991. The method ofclaim 6987, wherein controlling at least one condition in the formationcomprises controlling a temperature within at least a portion of theformation.
 6992. The method of claim 6987, wherein controlling at leastone condition in the formation comprises controlling a heating ratewithin at least a portion of the formation.
 6993. The method of claim6987, further comprising separating the produced fluids into one or morefractions using distillation.
 6994. The method of claim 6987, furthercomprising separating the produced fluids into one or more fractionsusing condensation.
 6995. The method of claim 6987, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and further comprisingproviding the heart cut to an extraction unit, and separating at leastsome pyrroles from the heart cut.
 6996. The method of claim 6987,further comprising separating the produced fluids into one or morefractions wherein the one or more fractions comprise a pyrrolesfraction, and further comprising providing the pyrroles fraction to anextraction unit, and separating at least some pyrroles from the pyrrolesfraction.
 6997. The method of claim 6987, wherein the heat provided fromat least one heater is transferred to the formation substantially byconduction.
 6998. The method of claim 6987, wherein the formation fluidsare produced from the formation when a partial pressure of hydrogen inat least a portion the formation is at least about 0.5 bars absolute.6999. A method of separating pyrroles from fluids produced from ahydrocarbon containing formation, comprising: separating pyrroles fromthe produced fluids, wherein the produced fluids are obtained by:providing heat from one or more heaters to at least a portion of theformation; allowing the heat to transfer from at least one or moreheaters to a selected section of the formation; and producing fluidsfrom the formation, wherein the produced fluids comprise pyrroles. 7000.The method of claim 6999, further comprising controlling a fluidpressure within at least a portion of the formation.
 7001. The method ofclaim 6999, further comprising controlling a temperature gradient withinat least a portion of the formation.
 7002. The method of claim 6999,further comprising controlling a temperature within at least a portionof the formation.
 7003. The method of claim 6999, further comprisingcontrolling a heating rate within at least a portion of the formation.7004. The method of claim 6999, wherein separating at least somepyrroles from the produced fluids further comprises separating theproduced fluids into one or more fractions using distillation.
 7005. Themethod of claim 6999, wherein separating at least some pyrroles from theproduced fluids further comprises separating the produced fluids intoone or more fractions using condensation.
 7006. The method of claim6999, wherein separating at least some pyrroles from the produced fluidsfurther comprises separating the produced fluids into one or morefractions wherein the one or more fractions comprise a heart cut, andextracting at least a portion of the pyrroles from the heart cut. 7007.The method of claim 6999, wherein separating at least some pyrroles fromthe produced fluids further comprises removing a naphtha fraction fromthe produced fluids, and separating at least a portion of the pyrrolesfrom the naphtha fraction.
 7008. The method of claim 6999, whereinseparating at least some pyrroles from the produced fluids furthercomprises removing an pyrroles fraction from the produced fluids, andseparating at least a portion of the pyrroles from the pyrrolesfraction.
 7009. The method of claim 6999, wherein separating thepyrroles from the produced fluids further comprises removing pyrrolesusing distillation.
 7010. The method of claim 6999, wherein separatingthe pyrroles from the produced fluids further comprises removingpyrroles using crystallization.
 7011. The method of claim 6999, whereinthe heat provided from at least one heater is transferred to theformation substantially by conduction.
 7012. The method of claim 6999,wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7013. A method of enhancing thiophenesproduction from a hydrocarbon containing formation, comprising:controlling at least one condition within at least a portion of theformation to enhance production of thiophenes in formation fluid,wherein the formation fluid is obtained by: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from at least one or more heaters to a selected section ofthe formation; and producing formation fluids from the formation. 7014.The method of claim 7013, further comprising separating at least aportion of the thiophenes from the produced fluids.
 7015. The method ofclaim 7013, wherein controlling at least one condition in the formationcomprises controlling a fluid pressure within at least a portion of theformation.
 7016. The method of claim 7013, wherein controlling at leastone condition in the formation comprises controlling a temperaturegradient within at least a portion of the formation.
 7017. The method ofclaim 7013, wherein controlling at least one condition in the formationcomprises controlling a temperature within at least a portion of theformation.
 7018. The method of claim 7013, wherein controlling at leastone condition in the formation comprises controlling a heating ratewithin at least a portion of the formation.
 7019. The method of claim7013, further comprising separating the produced fluids into one or morefractions using distillation.
 7020. The method of claim 7013, furthercomprising separating the produced fluids into one or more fractionsusing condensation.
 7021. The method of claim 7013, further comprisingseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and further comprisingproviding the heart cut to an extraction unit, and separating at leastsome thiophenes from the heart cut.
 7022. The method of claim 7013,further comprising separating the produced fluids into one or morefractions wherein the one or more fractions comprise a thiophenesfraction, and further comprising providing the thiophenes fraction to anextraction unit, and separating at least some thiophenes from thethiophenes fraction.
 7023. The method of claim 7013, wherein the heatprovided from at least one heater is transferred to the formationsubstantially by conduction.
 7024. The method of claim 7013, wherein theformation fluids are produced from the formation when a partial pressureof hydrogen in at least a portion the formation is at least about 0.5bars absolute.
 7025. A method of separating thiophenes from fluidsproduced from a hydrocarbon containing formation, comprising: separatingthiophenes from the produced fluids, wherein the produced fluids areobtained by: providing heat from one or more heaters to at least aportion of the formation; allowing the heat to transfer from at leastone or more heaters to a selected section of the formation; andproducing fluids from the formation, wherein the produced fluidscomprise thiophenes.
 7026. The method of claim 7025, further comprisingcontrolling a fluid pressure within at least a portion of the formation.7027. The method of claim 7025, further comprising controlling atemperature gradient within at least a portion of the formation. 7028.The method of claim 7025, further comprising controlling a temperaturewithin at least a portion of the formation.
 7029. The method of claim7025, further comprising controlling a heating rate within at least aportion of the formation.
 7030. The method of claim 7025, whereinseparating at least some thiophenes from the produced fluids furthercomprises separating the produced fluids into one or more fractionsusing distillation.
 7031. The method of claim 7025, wherein separatingat least some thiophenes from the produced fluids further comprisesseparating the produced fluids into one or more fractions usingcondensation.
 7032. The method of claim 7025, wherein separating atleast some thiophenes from the produced fluids further comprisesseparating the produced fluids into one or more fractions wherein theone or more fractions comprise a heart cut, and extracting at least aportion of the thiophenes from the heart cut.
 7033. The method of claim7025, wherein separating at least some thiophenes from the producedfluids further comprises removing a naphtha fraction from the producedfluids, and separating at least a portion of the thiophenes from thenaphtha fraction.
 7034. The method of claim 7025, wherein separating atleast some thiophenes from the produced fluids further comprisesremoving an thiophenes fraction from the produced fluids, and separatingat least a portion of the thiophenes from the thiophenes fraction. 7035.The method of claim 7025, wherein separating the thiophenes from theproduced fluids further comprises removing thiophenes usingdistillation.
 7036. The method of claim 7025, wherein separating thethiophenes from the produced fluids further comprises removingthiophenes using crystallization.
 7037. The method of claim 7025,wherein the heat provided from at least one heater is transferred to theformation substantially by conduction.
 7038. The method of claim 7025,wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7039. A method of treating a hydrocarboncontaining formation comprising: providing a barrier to at least aportion of the formation to inhibit migration of fluids into or out of atreatment area of the formation; providing heat from one or more heatersto the treatment area; allowing the heat to transfer from the treatmentarea to a selected section of the formation; and producing fluids fromthe formation.
 7040. The method of claim 7039, wherein the heat providedfrom at least one of the one or more heaters is transferred to at leasta portion of the formation substantially by conduction.
 7041. The methodof claim 7039, wherein the fluids are produced from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 7042. The method of claim 7039, furthercomprising hydraulically isolating the treatment area from a surroundingportion of the formation.
 7043. The method of claim 7039, furthercomprising pyrolyzing at least a portion of hydrocarbon containingmaterial within the treatment area.
 7044. The method of claim 7039,further comprising generating synthesis gas in at least a portion of thetreatment area.
 7045. The method of claim 7039, further comprisingcontrolling a pressure within the treatment area.
 7046. The method ofclaim 7039, further comprising controlling a temperature within thetreatment area.
 7047. The method of claim 7039, further comprisingcontrolling a heating rate within the treatment area.
 7048. The methodof claim 7039, further comprising controlling an amount of fluid removedfrom the treatment area.
 7049. The method of claim 7039, wherein atleast section of the barrier comprises one or more sulfur wells. 7050.The method of claim 7039, wherein at least section of the barriercomprises one or more dewatering wells.
 7051. The method of claim 7039,wherein at least section of the barrier comprises one or more injectionwells and one or more dewatering wells.
 7052. The method of claim 7039,wherein providing a barrier comprises: providing a circulating fluid tothe a portion of the formation surrounding the treatment area; andremoving the circulating fluid proximate the treatment area.
 7053. Themethod of claim 7039, wherein at least section of the barrier comprisesa ground cover on a surface of the earth.
 7054. The method of claim7053, wherein at least section of the ground cover is sealed to asurface of the earth.
 7055. The method of claim 7039, further comprisinginhibiting a release of formation fluid to the earth's atmosphere with aground cover; and freezing at least a portion of the ground cover to asurface of the earth.
 7056. The method of claim 7039, further comprisinginhibiting a release of formation fluid to the earth's atmosphere. 7057.The method of claim 7039, further comprising inhibiting fluid seepagefrom a surface of the earth into the treatment area.
 7058. The method ofclaim 7039, wherein at least a section of the barrier is naturallyoccurring.
 7059. The method of claim 7039, wherein at least a section ofthe barrier comprises a low temperature zone.
 7060. The method of claim7039, wherein at least a section of the barrier comprises a frozen zone.7061. The method of claim 7039, wherein the barrier comprises aninstalled portion and a naturally occurring portion.
 7062. The method ofclaim 7039, further comprising: hydraulically isolating the treatmentarea from a surrounding portion of the formation; and maintaining afluid pressure within the treatment area at a pressure greater thanabout a fluid pressure within the surrounding portion of the formation.7063. The method of claim 7039, wherein at least a section of thebarrier comprises an impermeable section of the formation.
 7064. Themethod of claim 7039, wherein the barrier comprises a self-sealingportion.
 7065. The method of claim 7039, wherein the one or more heatersare positioned at a distance greater than about 5 m from the barrier.7066. The method of claim 7039, wherein at least one of the one or moreheaters is positioned at a distance less than about 1.5 m from thebarrier.
 7067. The method of claim 7039, wherein at least a portion ofthe barrier comprises a low temperature zone, and further comprisinglowering a temperature within the low temperature zone to a temperatureless than about a freezing temperature of water.
 7068. The method ofclaim 7039, wherein the barrier comprises a barrier well and furthercomprising positioning at least a portion of the barrier well below awater table of the formation.
 7069. The method of claim 7039, whereinthe treatment area comprises a first treatment area and a secondtreatment area, and further comprising: treating the first treatmentarea using a first treatment process; and treating the second treatmentarea using a second treatment process.
 7070. A method of treating ahydrocarbon containing formation in situ, comprising: providing arefrigerant to a plurality of barrier wells placed in a portion of theformation; establishing a frozen barrier zone to inhibit migration offluids into or out of a treatment area; providing heat from one or moreheaters to the treatment area; allowing the heat to transfer from thetreatment area to a selected section; and producing fluids from theformation.
 7071. The method of claim 7070, wherein the heat providedfrom at least one of the one or more heaters is transferred to at leasta portion of the formation substantially by conduction.
 7072. The methodof claim 7070, wherein the fluids are produced from the formation when apartial pressure of hydrogen in at least a portion the formation is atleast about 0.5 bars absolute.
 7073. The method of claim 7070, furthercomprising controlling a fluid pressure within the treatment area. 7074.The method of claim 7070, wherein the frozen barrier zone is proximatethe treatment area of the formation.
 7075. The method of claim 7070,further comprising hydraulically isolating the treatment area from asurrounding portion of the formation.
 7076. The method of claim 7070,further comprising thermally isolating the treatment area from asurrounding portion of the formation.
 7077. The method of claim 7070,further comprising maintaining the fluid pressure above a hydrostaticpressure of the formation.
 7078. The method of claim 7070, furthercomprising removing liquid water from at least a portion of thetreatment area.
 7079. The method of claim 7070, wherein the treatmentarea is below a water table of the formation.
 7080. The method of claim7070, wherein at least one barrier well of the plurality of barrierwells comprises a corrosion inhibitor.
 7081. The method of claim 7070,wherein heating is initiated after formation of the frozen barrier zone.7082. The method of claim 7070, wherein the refrigerant comprises one ormore hydrocarbons.
 7083. The method of claim 7070, wherein therefrigerant comprises propane.
 7084. The method of claim 7070, whereinthe refrigerant comprises isobutane.
 7085. The method of claim 7070,wherein the refrigerant comprises cyclopentane.
 7086. The method ofclaim 7070, wherein the refrigerant comprises ammonia.
 7087. The methodof claim 7070, wherein the refrigerant comprises an aqueous saltmixture.
 7088. The method of claim 7070, wherein the refrigerantcomprises an organic acid salt.
 7089. The method of claim 7070, whereinthe refrigerant comprises a salt of an organic acid.
 7090. The method ofclaim 7070, wherein the refrigerant comprises an organic acid.
 7091. Themethod of claim 7070, wherein the refrigerant has a freezing point ofless than about minus 60 degrees Celsius.
 7092. The method of claim7070, wherein the refrigerant comprises calcium chloride.
 7093. Themethod of claim 7070, wherein the refrigerant comprises lithiumchloride.
 7094. The method of claim 7070, wherein the refrigerantcomprises liquid nitrogen.
 7095. The method of claim 7070, wherein therefrigerant is provided at a temperature of less than about minus 50degrees Celsius.
 7096. The method of claim 7070, wherein the refrigerantcomprises carbon dioxide.
 7097. The method of claim 7070, wherein atleast one of the plurality of barrier wells is located along strike of ahydrocarbon containing portion of the formation.
 7098. The method ofclaim 7070, wherein at least one of the plurality of barrier wells islocated along dip of a hydrocarbon containing portion of the formation.7099. The method of claim 7070, wherein the one or more heaters areplaced greater than about 5 m from a frozen barrier zone.
 7100. Themethod of claim 7070, wherein at least one of the one or more heaters ispositioned less than about 1.5 m from a frozen barrier zone.
 7101. Themethod of claim 7070, wherein a distance between a center of at leastone barrier well and a center of at least one adjacent barrier well isgreater than about 2 m.
 7102. The method of claim 7070, furthercomprising desorbing methane from the formation.
 7103. The method ofclaim 7070, further comprising pyrolyzing at least some hydrocarboncontaining material within the treatment area.
 7104. The method of claim7070, further comprising producing synthesis gas from at least a portionof the formation.
 7105. The method of claim 7070, further comprising:providing a solvent to the treatment area such that the solventdissolves a component in the treatment area; and removing the solventfrom the treatment area, wherein the removed solvent comprises thecomponent.
 7106. The method of claim 7070, further comprisingsequestering a compound in at least a portion of the treatment area.7107. The method of claim 7070, further comprising thawing at least aportion of the frozen barrier zone; and wherein material in a thawedbarrier zone area is substantially unaltered by the application of heat.7108. The method of claim 7070, wherein a location of the frozen barrierzone has been selected using a flow rate of groundwater and wherein theselected groundwater flow rate is less than about 50 m/day.
 7109. Themethod of claim 7070, further comprising providing water to the frozenbarrier zone.
 7110. The method of claim 7070, further comprisingpositioning one or more monitoring wells outside the frozen barrierzone, and then providing a tracer to the treatment area, and thenmonitoring for movement of the tracer at the monitoring wells.
 7111. Themethod of claim 7070, further comprising: positioning one or moremonitoring wells outside the frozen barrier zone; then providing anacoustic pulse to the treatment area; and then monitoring for theacoustic pulse at the monitoring wells.
 7112. The method of claim 7070,wherein a fluid pressure within the treatment area can be controlled atfluid pressures different from a fluid pressure that exists in asurrounding portion of the formation.
 7113. The method of claim 7070,wherein fluid pressure within an area at least partially bounded by thefrozen barrier zone can be controlled higher than, or lower than,hydrostatic pressures that exist in a surrounding portion of theformation.
 7114. The method of claim 7070, further comprisingcontrolling compositions of fluids produced from the formation bycontrolling the fluid pressure within an area at least partially boundedby the frozen barrier zone.
 7115. The method of claim 7070, wherein aportion of at least one of the plurality of barrier wells is positionedbelow a water table of the formation.
 7116. A method of treating ahydrocarbon containing formation comprising: providing a refrigerant toone or more barrier wells placed in a portion of the formation;establishing a low temperature zone proximate a treatment area of theformation; providing heat from one or more heaters to a treatment areaof the formation; allowing the heat to transfer from the treatment areato a selected section of the formation; and producing fluids from theformation.
 7117. The method of claim 7116, further comprising forming afrozen barrier zone within the low temperature zone, wherein the frozenbarrier zone hydraulically isolates the treatment area from asurrounding portion of the formation.
 7118. The method of claim 7116,further comprising forming a frozen barrier zone within the lowtemperature zone, and wherein fluid pressure within an area at leastpartially bounded by the frozen barrier zone can be controlled atdifferent fluid pressures from the fluid pressures that exist outside ofthe frozen barrier zone.
 7119. The method of claim 7116, furthercomprising forming a frozen barrier zone within the low temperaturezone, and wherein fluid pressure within an area at least partiallybounded by the frozen barrier zone can be controlled higher than, orlower than, hydrostatic pressures that exist outside of the frozenbarrier zone.
 7120. The method of claim 7116, further comprising forminga frozen barrier zone within the low temperature zone, and wherein fluidpressure within an area at least partially bounded by the frozen barrierzone can be controlled higher than, or lower than, hydrostatic pressuresthat exist outside of the frozen barrier zone, and further comprisingcontrolling compositions of fluids produced from the formation bycontrolling the fluid pressure within the area at least partiallybounded by the frozen barrier zone.
 7121. The method of claim 7116,further comprising thawing at least a portion of the low temperaturezone, wherein material within the thawed portion is substantiallyunaltered by the application of heat such that the structural integrityof the hydrocarbon containing formation is substantially maintained.7122. The method of claim 7116, wherein an inner boundary of the lowtemperature zone is determined by monitoring a pressure wave using oneor more piezometers.
 7123. The method of claim 7116, further comprisingcontrolling a fluid pressure within the treatment area at a pressureless than about a formation fracture pressure.
 7124. The method of claim7116, further comprising positioning one or more monitoring wellsoutside the frozen barrier zone, and then providing an acoustic pulse tothe treatment area, and then monitoring for the acoustic pulse at themonitoring wells.
 7125. The method of claim 7116, further comprisingpositioning a segment of at least one of the one or more barrier wellsbelow a water table of the formation.
 7126. The method of claim 7116,further comprising positioning the one or more barrier wells toestablish a continuous low temperature zone.
 7127. The method of claim7116, wherein the refrigerant comprises one or more hydrocarbons. 7128.The method of claim 7116, wherein the refrigerant comprises propane.7129. The method of claim 7116, wherein the refrigerant comprisesisobutane.
 7130. The method of claim 7116, wherein the refrigerantcomprises cyclopentane.
 7131. The method of claim 7116, wherein therefrigerant comprises ammonia.
 7132. The method of claim 7116, whereinthe refrigerant comprises an aqueous salt mixture.
 7133. The method ofclaim 7116, wherein the refrigerant comprises an organic acid salt.7134. The method of claim 7116, wherein the refrigerant comprises a saltof an organic acid.
 7135. The method of claim 7116, wherein therefrigerant comprises an organic acid.
 7136. The method of claim 7116,wherein the refrigerant has a freezing point of less than about minus 60degrees Celsius.
 7137. The method of claim 7116, wherein the refrigerantis provided at a temperature of less than about minus 50 degreesCelsius.
 7138. The method of claim 7116, wherein the refrigerant isprovided at a temperature of less than about minus 25 degrees Celsius.7139. The method of claim 7116, wherein the refrigerant comprises carbondioxide.
 7140. The method of claim 7116, further comprising: cooling atleast a portion of the refrigerant in an absorption refrigeration unit;and providing a thermal energy source to the absorption refrigerationunit.
 7141. The method of claim 7116, wherein the thermal energy sourcecomprises water.
 7142. The method of claim 7116, wherein the thermalenergy source comprises steam.
 7143. The method of claim 7116, whereinthe thermal energy source comprises at least a portion of the producedfluids.
 7144. The method of claim 7116, wherein the thermal energysource comprises exhaust gas.
 7145. A method of treating a hydrocarboncontaining formation, comprising: inhibiting migration of fluids into orout of a treatment area of the formation from a surrounding portion ofthe formation; providing heat from one or more heaters to at least aportion of the treatment area; allowing the heat to transfer from atleast the portion to a selected section of the formation; and producingfluids from the formation.
 7146. The method of claim 7145, wherein theheat provided from at least one of the one or more heaters istransferred to at least a portion of the formation substantially byconduction.
 7147. The method of claim 7145, wherein the fluids areproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 7148.The method of claim 7145, further comprising providing a barrier to atleast a portion of the formation.
 7149. The method of claim 7148,wherein at least section of the barrier comprises one or more sulfurwells.
 7150. The method of claim 7148, wherein at least section of thebarrier comprises one or more pumping wells.
 7151. The method of claim7148, wherein at least section of the barrier comprises one or moreinjection wells and one or more pumping wells.
 7152. The method of claim7148, wherein at least a section of the barrier is naturally occurring.7153. The method of claim 7145, further comprises establishing a barrierin at least a portion of the formation, and wherein heat is providedafter at least a portion of the barrier has been established.
 7154. Themethod of claim 7145, further comprising establishing a barrier in atleast a portion of the formation, and wherein heat is provided while atleast a portion of the barrier is being established.
 7155. The method ofclaim 7145, further comprising providing a barrier to at least a portionof the formation, and wherein heat is provided before the barrier isestablished.
 7156. The method of claim 7145, further comprisingcontrolling an amount of fluid removed from the treatment area. 7157.The method of claim 7145, wherein isolating a treatment area from asurrounding portion of the formation comprises providing a lowtemperature zone to at least a portion of the formation.
 7158. Themethod of claim 7145, wherein isolating a treatment area from asurrounding portion of the formation comprises providing a frozenbarrier zone to at least a portion of the formation.
 7159. The method ofclaim 7145, wherein isolating a treatment area from a surroundingportion of the formation comprises providing a grout wall.
 7160. Themethod of claim 7145, further comprising inhibiting flow of water intoor out of at least a portion of a treatment area.
 7161. The method ofclaim 7145, further comprising: providing a material to the treatmentarea; and storing at least some of the material within the treatmentarea.
 7162. A method of treating a hydrocarbon containing formation,comprising: providing a barrier to a portion of the formation, whereinthe portion has previously undergone an in situ conversion process; andinhibiting migration of fluids into and out of the converted portion toa surrounding portion of the formation.
 7163. The method of claim 7162,wherein the barrier comprises a frozen barrier zone.
 7164. The method ofclaim 7162, wherein the barrier comprises a low temperature zone. 7165.The method of claim 7162, wherein the barrier comprises a sealingmineral phase.
 7166. The method of claim 7162, wherein the barriercomprises a sulfur barrier.
 7167. The method of claim 7162, wherein thecontaminant comprises a metal.
 7168. The method of claim 7162, whereinthe contaminant comprises organic residue.
 7169. A method of treating ahydrocarbon containing formation, comprising: introducing a first fluidinto at least a portion of the formation, wherein the portion haspreviously undergone an in situ conversion process; producing a mixtureof the first fluid and a second fluid from the formation; and providingat least a portion of the mixture to an energy producing unit.
 7170. Themethod of claim 7169, wherein the first fluid is selected to recoverheat from the formation.
 7171. The method of claim 7169, wherein thefirst fluid is selected to recover heavy compounds from the formation.7172. The method of claim 7169, wherein the first fluid is selected torecover hydrocarbons from the formation.
 7173. The method of claim 7169,wherein the mixture comprises an oxidizable heat recovery fluid. 7174.The method of claim 7169, wherein producing the mixture remediates theportion of the formation by removing contaminants from the formation inthe mixture.
 7175. The method of claim 7169, wherein the first fluidcomprises a hydrocarbon fluid.
 7176. The method of claim 7169, whereinthe first fluid comprises methane.
 7177. The method of claim 7169,wherein the first fluid comprises ethane.
 7178. The method of claim7169, wherein the first fluid comprises molecular hydrogen.
 7179. Themethod of claim 7169, wherein the energy producing unit comprises aturbine, and generating electricity by passing mixture through theenergy producing unit.
 7180. The method of claim 7169, furthercomprising combusting mixture within the energy producing unit. 7181.The method of claim 7169, further comprising inhibiting spread of themixture from the portion of the formation with a barrier.
 7182. A methodof treating a hydrocarbon containing formation, comprising: providing afirst fluid to at least a portion of a treatment area, wherein thetreatment area includes one or more components; producing a fluid fromthe formation wherein the produced fluid comprises first fluid and atleast some of the one or more components; and wherein the treatment areais obtained by providing heat from heaters to a portion of a hydrocarboncontaining formation to convert a portion of hydrocarbons to desiredproducts and removing a portion of the desired hydrocarbons from theformation.
 7183. The method of claim 7182, wherein the first fluidcomprises water.
 7184. The method of claim 7182, wherein the first fluidcomprises carbon dioxide.
 7185. The method of claim 7182, wherein thefirst fluid comprises steam.
 7186. The method of claim 7182, wherein thefirst fluid comprises air.
 7187. The method of claim 7182, wherein thefirst fluid comprises a combustible gas.
 7188. The method of claim 7182,wherein the first fluid comprises hydrocarbons.
 7189. The method ofclaim 7182, wherein the first fluid comprises methane.
 7190. The methodof claim 7182, wherein the first fluid comprises ethane.
 7191. Themethod of claim 7182, wherein the first fluid comprises molecularhydrogen.
 7192. The method of claim 7182, wherein the first fluidcomprises propane.
 7193. The method of claim 7182, further comprisingreacting a portion of the contaminants with the first fluid.
 7194. Themethod of claim 7182, further comprising providing at least a portion ofthe produced fluid to an energy generating unit to generate electricity.7195. The method of claim 7182, further comprising providing at least aportion of the produced fluid to a combustor.
 7196. The method of claim7182, wherein a frozen barrier defines at least a segment of a barrierwithin the formation, allowing a portion of the frozen barrier to thawprior to providing the first fluid to the treatment area, and providingat least some of the first fluid into the thawed portion of the barrier.7197. The method of claim 7182, wherein a volume of first fluid providedto the treatment area is greater than about one pore volume of thetreatment area.
 7198. The method of claim 7182, further comprisingseparating contaminants from the first fluid.
 7199. A method ofrecovering thermal energy from a heated hydrocarbon containingformation, comprising: injecting a heat recovery fluid into a heatedportion of the formation; allowing heat from the portion of theformation to transfer to the heat recovery fluid; and producing fluidsfrom the formation.
 7200. The method of claim 7199, wherein the heatrecovery fluid comprises water.
 7201. The method of claim 7199, whereinthe heat recovery fluid comprises saline water.
 7202. The method ofclaim 7199, wherein the heat recovery fluid comprises non-potable water.7203. The method of claim 7199, wherein the heat recovery fluidcomprises alkaline water.
 7204. The method of claim 7199, wherein theheat recovery fluid comprises hydrocarbons.
 7205. The method of claim7199, wherein the heat recovery fluid comprises an inert gas.
 7206. Themethod of claim 7199, wherein the heat recovery fluid comprises carbondioxide.
 7207. The method of claim 7199, wherein the heat recovery fluidcomprises a product stream produced by an in situ conversion process.7208. The method of claim 7199, further comprising vaporizing at leastsome of the heat recovery fluid.
 7209. The method of claim 7199, whereinan average temperature of the portion of the post treatment formationprior to injection of heat recovery fluid is greater than about 300° C.7210. The method of claim 7199, further comprising providing the heatrecovery fluid to the formation through a heater well.
 7211. The methodof claim 7199, wherein fluids are produced from one or more productionwells in the formation.
 7212. The method of claim 7199, furthercomprising providing at least some of the produced fluids to a treatmentprocess in a section of the formation.
 7213. The method of claim 7199,further comprising recovering at least some of the heat from theproduced fluids.
 7214. The method of claim 7199, further comprisingproviding at least some of the produced fluids to a power generatingunit.
 7215. The method of claim 7199, further comprising providing atleast some of the produced fluids to a heat exchange mechanism. 7216.The method of claim 7199, further comprising providing at least some ofthe produced fluids to a steam cracking unit.
 7217. The method of claim7199, further comprising providing at least some of the produced fluidsto a hydrotreating unit.
 7218. The method of claim 7199, furthercomprising providing at least some of the produced fluids to adistillation column.
 7219. The method of claim 7199, wherein the heatrecovery fluid comprises carbon dioxide, and wherein at least some ofthe carbon dioxide is adsorbed onto the surface of carbon in theformation.
 7220. The method of claim 7199, wherein the heat recoveryfluid comprises carbon dioxide, and further comprising: allowing atleast some hydrocarbons within the formation to desorb from theformation; and producing at least some of the desorbed hydrocarbons fromthe formation.
 7221. The method of claim 7199, further comprisingproviding at least some of the produced fluids to a treatment process ina section of the formation.
 7222. The method of claim 7199, wherein theheat recovery fluid is saline water, and further comprising: providingcarbon dioxide to the portion of the formation; and precipitatingcarbonate compounds.
 7223. The method of claim 7199, further comprisingreducing an average temperature of the formation to a temperature lessthan about an ambient boiling temperature of water at a post treatmentpressure.
 7224. The method of claim 7199, wherein the produced fluidscomprise low molecular weight hydrocarbons.
 7225. The method of claim7199, wherein the produced fluids comprise hydrocarbons.
 7226. Themethod of claim 7199, wherein the produced fluids comprise heat recoveryfluid.
 7227. A method of treating a hydrocarbon containing formation,comprising: providing heat from one or more heaters to at least aportion of the formation; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; controlling atleast one condition within the selected section; producing a mixturefrom the formation; and wherein at least the one condition is controlledsuch that the mixture comprises a carbon dioxide emission level lessthan about a selected carbon dioxide emission level.
 7228. The method ofclaim 7227, wherein the heat provided from at least one heater istransferred to at least a portion of the formation substantially byconduction.
 7229. The method of claim 7227, wherein the mixture isproduced from the formation when a partial pressure of hydrogen in atleast a portion the formation is at least about 0.5 bars absolute. 7230.The method of claim 7227, wherein the selected carbon dioxide emissionlevel is less than about 5.6×10⁻⁸ kg CO₂ produced for every Joule ofenergy.
 7231. The method of claim 7227, wherein the selected carbondioxide emission level is less than about 1.6×10⁻⁸ kg CO₂ produced forevery Joule of energy.
 7232. The method of claim 7227, wherein theselected carbon dioxide emission level is less than about 1.6×10⁻¹⁰ kgCO₂ produced for every Joule of energy.
 7233. The method of claim 7227,further comprising blending the mixture with a fluid to form a blendedproduct comprising a carbon dioxide emission level less than about theselected baseline carbon dioxide emission level.
 7234. The method ofclaim 7227, wherein controlling conditions within a selected sectioncomprises controlling a pressure within the selected section.
 7235. Themethod of claim 7227, wherein controlling conditions within a selectedsection comprises controlling an average temperature within the selectedsection.
 7236. The method of claim 7227, wherein controlling conditionswithin a selected section comprises controlling an average heating ratewithin the selected section.
 7237. A method for producing molecularhydrogen from a hydrocarbon containing formation, comprising: providingheat from one or more heaters to at least one portion of the formationsuch that carbon dioxide production is minimized; allowing the heat totransfer from the one or more heaters to a selected section of theformation; producing a mixture comprising molecular hydrogen from theformation; and controlling the heat from the one or more heaters toenhance production of molecular hydrogen.
 7238. The method of claim7237, wherein the heat provided from at least one heater is transferredto at least a portion of the formation substantially by conduction.7239. The method of claim 7237, wherein the mixture is produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 7240. The method of claim7237, wherein controlling the heat comprises controlling a temperatureproximate the production wellbore at or above a decompositiontemperature of methane.
 7241. The method of claim 7237, wherein heat isgenerated by oxidizing molecular hydrogen in at least one heater. 7242.The method of claim 7237, wherein heat is generated by electricityproduced from wind power.
 7243. The method of claim 7237, wherein heatis generated from electrical power.
 7244. The method of claim 7237,wherein the heaters form an array of heaters.
 7245. The method of claim7237, further comprising heating at least a portion of the selectedsection of the formation to greater than about 600° C.
 7246. The methodof claim 7237, wherein the produced mixture is produced from aproduction wellbore, and further comprising controlling the heat fromone or more heaters such that the temperature in the formation proximatethe production wellbore is at least about 600° C.
 7247. The method ofclaim 7237, wherein the produced mixture is produced from a productionwellbore, and further comprising heating at least a portion of theformation with a heater proximate the production wellbore.
 7248. Themethod of claim 7237, further comprising recycling at least a portion ofthe produced molecular hydrogen into the formation.
 7249. The method ofclaim 7237, wherein the produced mixture comprises methane, and furthercomprising oxidizing at least a portion of the methane to provide heatto the formation.
 7250. The method of claim 7237, wherein controllingthe heat comprises maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 7251. The method of claim 7237,wherein the one or more heaters comprise one or more electrical heaterspowered by a fuel cell, and wherein at least a portion of the molecularhydrogen in the produced mixture is used in the fuel cell.
 7252. Themethod of claim 7237, further comprising controlling a pressure withinat least a majority of the selected section of the formation.
 7253. Themethod of claim 7237, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 3° C.per day during pyrolysis.
 7254. The method of claim 7237, whereinallowing the heat to transfer from the one or more heaters to theselected section comprises transferring heat substantially byconduction.
 7255. The method of claim 7237, wherein at least 50% byvolume of the produced mixture comprises molecular hydrogen.
 7256. Themethod of claim 7237, wherein less than about 3.3×10⁻⁸ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7257. Themethod of claim 7237, wherein less than about 1.6×10⁻¹⁰ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7258. Themethod of claim 7237, wherein less than about 3.3×10⁻¹⁰ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7259. Themethod of claim 7237, wherein the produced mixture is produced from aproduction wellbore, and further comprising controlling the heat fromone or more heaters such that the temperature in the formation proximatethe production wellbore is at least about 500° C.
 7260. The method ofclaim 7237, wherein the produced mixture comprises methane and molecularhydrogen, and further comprising: separating at least a portion of themolecular hydrogen from the produced mixture; and providing at least aportion of the separated mixture to at least one of the one or moreheaters for use as fuel.
 7261. The method of claim 7237, wherein theproduced mixture comprises methane and molecular hydrogen, and furthercomprising: separating at least a portion of the molecular hydrogen fromthe produced mixture; and providing at least some of the molecularhydrogen to a fuel cell to generate electricity.
 7262. A method forproducing methane from a hydrocarbon containing formation in situ whileminimizing production of CO₂, comprising: providing heat from one ormore heaters to at least one portion of the formation such that CO₂production is minimized; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; producing a mixturecomprising methane from the formation; and controlling the heat from theone or more heaters to enhance production of methane.
 7263. The methodof claim 7262, wherein the heat provided from at least one of the one ormore heater is transferred to at least a portion of the formationsubstantially by conduction.
 7264. The method of claim 7262, whereincontrolling the heat comprises controlling a temperature proximate theproduction wellbore at or above a decomposition temperature of ethane.7265. The method of claim 7262, wherein heat is generated by oxidizingmethane in at least one heater.
 7266. The method of claim 7262, whereinheat is generated by electricity produced from wind power.
 7267. Themethod of claim 7262, wherein heat is generated from electrical power.7268. The method of claim 7262, wherein the heaters form an array ofheaters.
 7269. The method of claim 7262, further comprising heating atleast a portion of the selected section of the formation to greater thanabout 400° C.
 7270. The method of claim 7262, wherein the producedmixture is produced from a production wellbore, and further comprisingcontrolling the heat from one or more heaters such that the temperaturein the formation proximate the production wellbore is at least about400° C.
 7271. The method of claim 7262, wherein the produced mixture isproduced from a production wellbore, and further comprising heating atleast a portion of the formation with a heater proximate the productionwellbore.
 7272. The method of claim 7262, further comprising recyclingat least a portion of the produced methane into the formation.
 7273. Themethod of claim 7262, wherein the produced mixture comprises methane,and further comprising oxidizing at least a portion of the methane toprovide heat to the formation.
 7274. The method of claim 7262, whereinthe one or more heaters comprise at least two heaters, and whereinsuperposition of heat from at least the two heaters pyrolyzes at leastsome hydrocarbons within the selected section of the formation. 7275.The method of claim 7262, wherein controlling the heat comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 7276. The method of claim 7262, wherein the one ormore heaters comprise one or more electrical heaters powered by a fuelcell, and wherein at least a portion of the molecular hydrogen in theproduced mixture is used in the fuel cell.
 7277. The method of claim7262, further comprising controlling a pressure within at least amajority of the selected section of the formation.
 7278. The method ofclaim 7262, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 3° C. per dayduring pyrolysis.
 7279. The method of claim 7262, wherein allowing theheat to transfer from the one or more heaters to the selected sectioncomprises transferring heat substantially by conduction.
 7280. Themethod of claim 7262, wherein less than about 8.4×10⁻⁸ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7281. Themethod of claim 7262, wherein less than about 7.4×10⁻⁸ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7282. Themethod of claim 7262, wherein less than about 5.6×10⁻⁸ kg CO₂ isproduced for every Joule of energy in the produced mixture.
 7283. Amethod for upgrading hydrocarbons in a hydrocarbon containing formation,comprising: providing heat from one or more heaters to a portion of theformation; allowing the heat to transfer from the first portion to aselected section of the formation; providing hydrocarbons to theselected section; and producing a mixture from the formation, whereinthe mixture comprises hydrocarbons that were provided to the selectedsection and upgraded in the formation.
 7284. The method of claim 7283,wherein the mixture is produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7285. The method of claim 7283, wherein theheat provided from at least one heater is transferred to at least aportion of the formation substantially by conduction.
 7286. The methodof claim 7283, wherein the provided hydrocarbons comprise heavyhydrocarbons.
 7287. The method of claim 7283, wherein the providedhydrocarbons comprise naphtha.
 7288. The method of claim 7283, whereinthe provided hydrocarbons comprise asphaltenes.
 7289. The method ofclaim 7283, wherein the provided hydrocarbons comprise crude oil. 7290.The method of claim 7283, wherein the provided hydrocarbons comprisesurface mined tar from relatively permeable formations.
 7291. The methodof claim 7283, wherein the provided hydrocarbons comprise an emulsionproduced from a relatively permeable formation, and further comprisingproviding the produced emulsion to the first portion after a temperaturein the selected section is greater than about a pyrolysis temperature.7292. The method of claim 7283, further comprising providing steam tothe selected section.
 7293. The method of claim 7283, furthercomprising: producing formation fluids from the formation; separatingthe produced formation fluids into one or more components; and whereinthe provided hydrocarbons comprise at least one of the one or morecomponents.
 7294. The method of claim 7283, further comprising:providing steam to the selected section, wherein the providedhydrocarbons are mixed with the steam; and controlling an amount ofsteam such that a residence time of the provided hydrocarbons within theselected section is controlled.
 7295. The method of claim 7283, whereinthe produced mixture comprises upgraded hydrocarbons, and furthercomprising controlling a residence time of the provided hydrocarbonswithin the selected section to control a molecular weight distributionwithin the upgraded hydrocarbons.
 7296. The method of claim 7283,wherein the produced mixture comprises upgraded hydrocarbons, andfurther comprising controlling a residence time of the providedhydrocarbons in the selected section to control an API gravity of theupgraded hydrocarbons.
 7297. The method of claim 7283, furthercomprising steam cracking in at least a portion of the selected section.7298. The method of claim 7283, wherein the provided hydrocarbons areproduced from a second portion of the formation.
 7299. The method ofclaim 7283, further comprising allowing some of the providedhydrocarbons to crack in the formation to generate upgradedhydrocarbons.
 7300. The method of claim 7283, further comprisingcontrolling a temperature of the first portion of the formation bycontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 7301. The method of claim 7283,further comprising controlling a pressure within at least a majority ofthe selected section of the formation.
 7302. The method of claim 7283,wherein a temperature in the first portion is greater than about apyrolysis temperature.
 7303. The method of claim 7283, furthercomprising: controlling the heat such that a temperature of the firstportion is greater than about a pyrolysis temperature of hydrocarbons;and producing at least some of the provided hydrocarbons from the firstportion of the formation.
 7304. The method of claim 7283, furthercomprising producing at least some of the provided hydrocarbons from asecond portion of the formation.
 7305. The method of claim 7283, furthercomprising: controlling the heat such that a temperature of a secondportion is less than about a pyrolysis temperature of hydrocarbons; andproducing at least some of the provided hydrocarbons from the secondportion of the formation.
 7306. The method of claim 7283, furthercomprising producing at least some of the provided hydrocarbons from asecond portion of the formation and wherein a temperature of the secondportion is about an ambient temperature of the formation.
 7307. Themethod of claim 7283, wherein the upgraded hydrocarbons are producedfrom a production well and wherein the heat is controlled such that theupgraded hydrocarbons can be produced from the formation as a vapor.7308. A method for producing methane from a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least one portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation;providing hydrocarbon fluids to at least the selected section of theformation; and producing mixture comprising methane from the formation.7309. The method of claim 7308, wherein the heat provided from at leastone heater is transferred to at least a portion of the formationsubstantially by conduction.
 7310. The method of claim 7308, furthercomprising controlling heat from at least one of the heaters to enhanceproduction of methane from the hydrocarbon fluids.
 7311. The method ofclaim 7308, further comprising controlling a temperature within at leasta selected section in a range to from greater than about 400° C. to lessthan about 600° C.
 7312. The method of claim 7308, further comprisingcooling the mixture to inhibit further reaction of the methane. 7313.The method of claim 7308, further comprising controlling at least somecondition in the formation to enhance production of methane.
 7314. Themethod of claim 7308, further comprising adding water to the formation.7315. The method of claim 7308, further comprising separating at least aportion of the methane from the mixture and recycling at least some ofthe separated mixture to the formation.
 7316. The method of claim 7308,further comprising cracking the hydrocarbon fluids to form methane.7317. The method of claim 7308, wherein the mixture is produced from theformation through a production well, and wherein the heat is controlledsuch that the mixture can be produced from the formation as a vapor.7318. The method of claim 7308, wherein the mixture is produced from theformation through a production well, and further comprising heating awellbore of the production well to inhibit condensation of the mixturewithin the wellbore.
 7319. The method of claim 7308, wherein the mixtureis produced from the formation through a production well, wherein awellbore of the production well comprises a heater element configured toheat the formation adjacent to the wellbore, and further comprisingheating the formation with the heater element to produce the mixture.7320. A method for hydrotreating a fluid in a heated formation in situ,comprising: providing heat from one or more heaters to at least oneportion of the formation; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; providing a fluidto the selected section; controlling a H₂ partial pressure in theselected section of the formation; hydrotreating at least some of thefluid in the selected section; and producing a mixture comprisinghydrotreated fluids from the formation.
 7321. The method of claim 7320,wherein the mixture is produced from the formation when a partialpressure of hydrogen in the selected section is at least about 0.5 barsabsolute.
 7322. The method of claim 7320, wherein the heat provided fromat least one of the one or more heater is transferred to at least aportion of the formation substantially by conduction.
 7323. The methodof claim 7320, further comprising providing hydrogen to the selectedsection of the formation.
 7324. The method of claim 7320, furthercomprising controlling the heat such that a temperature within theselected section is in a range from about 200° C. to about 450° C. 7325.The method of claim 7320, wherein the provided fluid comprises anolefin.
 7326. The method of claim 7320, wherein the provided fluidcomprises pitch.
 7327. The method of claim 7320,wherein the providedfluid comprises oxygenated compounds.
 7328. The method of claim 7320,wherein the provided fluid comprises sulfur containing compounds. 7329.The method of claim 7320, wherein the provided fluid comprises nitrogencontaining compounds.
 7330. The method of claim 7320, wherein theprovided fluid comprises crude oil.
 7331. The method of claim 7320,wherein the provided fluid comprises synthetic crude oil.
 7332. Themethod of claim 7320, wherein the produced mixture comprises ahydrocarbon mixture.
 7333. The method of claim 7320, wherein theproduced mixture comprises less than about 1% by weight ammonia. 7334.The method of claim 7320, wherein the produced mixture comprises lessthan about 1% by weight hydrogen sulfide.
 7335. The method of claim7320, wherein the produced mixture comprises less than about 1%oxygenated compounds.
 7336. The method of claim 7320, further comprisingproducing the mixture from the formation through a production well,wherein the heating is controlled such that the mixture can be producedfrom the formation as a vapor.
 7337. A method for producing hydrocarbonsfrom a heated formation in situ, comprising: providing heat from one ormore heaters to at least one portion of the formation; allowing the heatto transfer from the one or more heaters to a selected section of theformation such that at least some of the selected section comprises atemperature profile; providing a hydrocarbon mixture to the selectedsection; separating the hydrocarbon mixture into one or more mixtures ofcomponents; and producing the one or more mixtures of components fromone or more production wells.
 7338. The method of claim 7337, whereinthe heat provided from at least one of the one or more heater istransferred to at least a portion of the formation substantially byconduction.
 7339. The method of claim 7337, wherein the one or more ofthe heaters comprise heaters.
 7340. The method of claim 7337, wherein atleast one of the one or more mixtures is produced from the formationwhen a partial pressure of hydrogen in at least a portion the formationis at least about 0.5 bars absolute.
 7341. The method of claim 7337,further comprising controlling a pressure within at least a majority ofthe selected section.
 7342. The method of claim 7337, wherein thetemperature profile extends horizontally through the formation. 7343.The method of claim 7337, wherein the temperature profile extendsvertically through the formation.
 7344. The method of claim 7337,wherein the selected section comprises a spent formation.
 7345. Themethod of claim 7337, wherein the production well comprises a pluralityof production wells placed at various distances from at least one of theone or more heaters along the temperature gradient zone.
 7346. Themethod of claim 7337, wherein the production well comprises a firstproduction well and a second production well, further comprising:positioning the first production well at a first distance from a heaterof the one or more heaters; positioning the second production well at asecond distance from the heater of the one or more heaters; producing afirst component of the one or more portions from the first productionwell; and producing a second component of the one or more portions fromthe second production well.
 7347. The method of claim 7337, furthercomprising heating a wellbore of the production well to inhibitcondensation of at least the one component within the wellbore. 7348.The method of claim 7337, wherein the one or more components comprisehydrocarbons.
 7349. The method of claim 7337, wherein separating the oneor more components further comprises: producing a low molecular weightcomponent of the one or more components from the formation; allowing ahigh molecular weight component of the one or more components to remainwithin the formation; providing additional heat to the formation; andproducing at least some of the high molecular weight component. 7350.The method of claim 7337, further comprising producing at least the onecomponent from the formation through a production well, wherein theheating is controlled such that the mixture can be produced from theformation as a vapor.
 7351. A method of utilizing heat of a heatedformation, comprising: placing a conduit in the formation,; allowingheat from the formation to transfer to at least a portion of theconduit; generating a region of reaction in the conduit; allowing amaterial to flow through the region of reaction; reacting at least someof the material in the region of reaction; and producing a mixture fromthe conduit.
 7352. The method of claim 7351, wherein a conduit input islocated separately from a conduit output
 7353. The method of claim 7351,wherein the conduit is configured to inhibit contact between thematerial and the formation.
 7354. The method of claim 7351, wherein theconduit comprises a u-shaped conduit, and further comprising placing theu-shaped conduit within a heater well in the heated formation.
 7355. Themethod of claim 7351, wherein the material comprises a first hydrocarbonand wherein the first hydrocarbon reacts to form a second hydrocarbon.7356. The method of claim 7351, wherein the material comprises water.7357. The method of claim 7351, wherein the produced mixture compriseshydrocarbons.
 7358. A method for storing fluids within a hydrocarboncontaining formation, comprising: providing a barrier to a portion ofthe formation to form an in situ storage area, wherein at least aportion of the in situ storage area has previously undergone an in situconversion process, and wherein migration of fluids into or out of thestorage area is inhibited; providing a material to the in situ storagearea; storing at least some of the provided fluids within the in situstorage area; and wherein one or more conditions of the in situ storagearea inhibits reaction within the material.
 7359. The method of claim7358, further comprising producing at least some of the stored materialfrom the in situ storage area.
 7360. The method of claim 7358, furthercomprising producing at least some of the stored material from the insitu storage area as a liquid.
 7361. The method of claim 7358, furthercomprising producing at least some of the stored material from the insitu storage area as a gas.
 7362. The method of claim 7358, wherein thestored material is a solid, and further comprising: providing a solventto the in situ storage area; allowing at least a portion of the storedmaterial to dissolve; and producing at least some of the dissolvedmaterial from the in situ storage area.
 7363. The method of claim 7358,wherein the material comprises inorganic compounds.
 7364. The method ofclaim 7358, wherein the material comprises organic compounds.
 7365. Themethod of claim 7358, wherein the material comprises hydrocarbons. 7366.The method of claim 7358, wherein the material comprises formationfluids
 7367. The method of claim 7358, wherein the material comprisessynthesis gas.
 7368. The method of claim 7358, wherein the materialcomprises a solid.
 7369. The method of claim 7358, wherein the materialcomprises a liquid.
 7370. The method of claim 7358, wherein the materialcomprises a gas.
 7371. The method of claim 7358, wherein the materialcomprises natural gas.
 7372. The method of claim 7358, wherein thematerial comprises compressed air.
 7373. The method of claim 7358,wherein the material comprises compressed air, and wherein thecompressed air is used as a supplement for electrical power generation.7374. The method of claim 7358, further comprising: producing at leastsome of the material from the in situ treatment area through aproduction well; and heating at least a portion of a wellbore of theproduction well to inhibit condensation of the material within thewellbore.
 7375. The method of claim 7358, wherein the in situ conversionprocess comprises pyrolysis.
 7376. The method of claim 7358, wherein thein situ conversion process comprises synthesis gas generation.
 7377. Themethod of claim 7358, wherein the in situ conversion process comprisessolution mining.
 7378. A method of filtering water within a hydrocarboncontaining formation comprising: providing water to at least a portionof the formation, wherein the portion has previously undergone an insitu conversion process, and wherein the water comprises one or morecomponents; removing at least one of the one or more components from theprovided water; and producing at least some of the water from theformation.
 7379. The method of claim 7378, wherein at least one of theone or more components comprises a dissolved cation, and furthercomprising: converting at least some of the provided water to steam;allowing at least some of the dissolved cation to remain in the portionof the formation; and producing at least a portion of the steam from theformation.
 7380. The method of claim 7378, wherein the portion of theformation is above the boiling point temperature of the provided waterat a pressure of the portion, wherein at least one of the one or morecomponents comprises mineral cations, and wherein the provided water isconverted to steam such that the mineral cations are deposited withinthe formation.
 7381. The method of claim 7378, further comprisingconverting at least a portion of the provided water into steam andwherein at least one of the one or more components is separated from thewater as the provided water is converted into steam.
 7382. The method ofclaim 7378, wherein a temperature of the portion of the formation isgreater than about 90° C., and further comprising sterilizing at leastsome of the provided water within the portion of the formation. 7383.The method of claim 7378, wherein a temperature within the portion isless than about a boiling temperature of the provided water at a fluidpressure of the portion.
 7384. The method of claim 7378, furthercomprising remediating at least the one portion of the formation. 7385.The method of claim 7378, wherein the one or more components comprisecations.
 7386. The method of claim 7378, wherein the one or morecomponents comprise calcium.
 7387. The method of claim 7378, wherein theone or more components comprise magnesium.
 7388. The method of claim7378, wherein the one or more components comprise a microorganism. 7389.The method of claim 7378, wherein the converted portion of the formationfurther comprises a pore size such that at least one of the one or morecomponents is removed from the provided water.
 7390. The method of claim7378, wherein the converted portion of the formation adsorbs at leastone of the one or more components in the provided water.
 7391. Themethod of claim 7378, wherein the provided water comprises formationwater.
 7392. The method of claim 7378, wherein the in situ conversionprocess comprises pyrolysis.
 7393. The method of claim 7378, wherein thein situ conversion process comprises synthesis gas generation.
 7394. Themethod of claim 7378, wherein the in situ conversion process comprisessolution mining.
 7395. A method for sequestering carbon dioxide in ahydrocarbon containing formation, comprising: providing carbon dioxideto a portion of the formation, wherein the portion has previouslyundergone an in situ conversion process; providing a fluid to theportion; allowing at least some of the provided carbon dioxide tocontact the fluid in the portion; and precipitating carbonate compounds.7396. The method of claim 7395, wherein providing a solution to theportion comprises allowing groundwater to flow into the portion. 7397.The method of claim 7395, wherein the solution comprises one or moredissolved ions.
 7398. The method of claim 7395, wherein the solutioncomprises a solution obtained from a formation aquifer.
 7399. The methodof claim 7395, wherein the solution comprises a man-made industrialsolution.
 7400. The method of claim 7395, wherein the solution comprisesagricultural run-off.
 7401. The method of claim 7395, wherein thesolution comprises seawater.
 7402. The method of claim 7395, wherein thesolution comprises a brine solution.
 7403. The method of claim 7395,further comprising controlling a temperature within the portion. 7404.The method of claim 7395, further comprising controlling a pressurewithin the portion.
 7405. The method of claim 7395, further comprisingremoving at least some of the solution from the formation.
 7406. Themethod of claim 7395, further comprising removing at least some of thesolution from the formation and recycling at least some of the removedsolution into the formation.
 7407. The method of claim 7395, furthercomprising providing a buffering compound to the solution.
 7408. Themethod of claim 7395, further comprising: providing the solution to theformation; and allowing at least some of the solution to migrate throughthe formation to increase a contact time between the solution and theprovided carbon dioxide.
 7409. The method of claim 7395, wherein thesolution is provided to the formation after carbon dioxide has beenprovided to the formation.
 7410. The method of claim 7395, furthercomprising providing heat to the portion.
 7411. The method of claim7395, wherein providing carbon dioxide to a portion of the formationcomprises providing carbon dioxide to a first location, whereinproviding a solution to the portion comprises providing the solution toa second location, and wherein the first location is downdip of thesecond location.
 7412. The method of claim 7395, wherein allowing atleast some of the provided carbon dioxide to contact the solution in theportion comprises allowing at least some of the carbon dioxide and atleast some of the solution to migrate past each other.
 7413. The methodof claim 7395, wherein the solution is provided to the formation priorto providing the carbon dioxide, and further comprising providing atleast some of the carbon dioxide to a location positioned proximate alower surface of the portion such that some of the carbon dioxide maymigrate up through the portion.
 7414. The method of claim 7395, whereinthe solution is provided to the formation prior to providing the carbondioxide, and further comprising allowing at least some carbon dioxide tomigrate through the portion.
 7415. The method of claim 7395, furthercomprising: providing heat to the portion, wherein the portion comprisesa temperature greater than about a boiling point of the solution;vaporizing at least some of the solution; producing a fluid from theformation.
 7416. The method of claim 7395, further comprising decreasingleaching of metals from the formation into groundwater.
 7417. A methodof treating a hydrocarbon containing formation, comprising: injecting arecovery fluid into a portion of the formation; allowing heat within therecovery fluid, and heat from one or more heaters, to transfer to aselected section of the formation, wherein the selected sectioncomprises hydrocarbons; mobilizing at least some of the hydrocarbonswithin the selected section; and producing a mixture from the formation.7418. The method of claim 7417, wherein the portion has been previouslyproduced.
 7419. The method of claim 7417, wherein the portion haspreviously undergone an in situ conversion process.
 7420. The method ofclaim 7417, further comprising upgrading at least some hydrocarbonswithin the selected section to decrease a viscosity of the hydrocarbons.7421. The method of claim 7417, wherein the produced mixture compriseshydrocarbons having an average API gravity greater than about 25°. 7422.The method of claim 7417, further comprising vaporizing at least some ofthe hydrocarbons within the selected section.
 7423. The method of claim7417, wherein the recovery fluid comprises water.
 7424. The method ofclaim 7417, wherein the recovery fluid comprises hydrocarbons.
 7425. Themethod of claim 7417, wherein the mixture comprises pyrolyzation fluids.7426. The method of claim 7417, wherein the mixture compriseshydrocarbons.
 7427. The method of claim 7417, wherein the mixture isproduced from a production well and further comprising controlling apressure such that a fluid pressure proximate to the production well isless than about a fluid pressure proximate to a location where the fluidis injected.
 7428. The method of claim 7417, further comprising:monitoring a composition of the produced mixture; and controlling afluid pressure in at least a portion of the formation to control thecomposition of the produced mixture.
 7429. The method of claim 7417,further comprising pyrolyzing at least some of the hydrocarbons withinthe selected section of the formation.
 7430. The method of claim 7417,wherein the formation comprises a heavy hydrocarbon containingformation.
 7431. The method of claim 7417, wherein the formationcomprises a bitumen formation.
 7432. The method of claim 7417, whereinthe formation comprises a relatively permeable formation.
 7433. Themethod of claim 7417, wherein the formation comprises a coal formation.7434. The method of claim 7417, wherein the formation comprises an oilshale formation.
 7435. The method of claim 7417, wherein the formationcomprises an oil containing formation.
 7436. The method of claim 7417,wherein the average temperature of the selected section is between about275° C. to about 375° C., and wherein a fluid pressure of the recoveryfluid is between about 60 bars to about 220 bars, and wherein therecovery fluid comprises steam.
 7437. The method of claim 7417, furthercomprising controlling pressure within the selected section such that afluid pressure within the selected section is at least about ahydrostatic pressure of a surrounding portion of the formation. 7438.The method of claim 7417, further comprising controlling pressure withinthe selected section such that a fluid pressure within the selectedsection is greater than about a hydrostatic pressure of a surroundingportion of the formation.
 7439. The method of claim 7417, wherein adepth of the selected section is between about 300 m to about 400 m.7440. The method of claim 7417, wherein the mixture comprises pyrolysisproducts.
 7441. The method of claim 7417, further comprising vaporizingat least some of the hydrocarbons within the selected section andwherein the vaporized hydrocarbons comprise hydrocarbons having a carbonnumber greater than about 1 and a carbon number less than about
 4. 7442.The method of claim 7417, further comprising allowing the injectedrecovery fluid to contact a substantial portion of a volume of theselected section.
 7443. The method of claim 7417, wherein the recoveryfluid comprises steam, and wherein the pressure of the injected steam isat least about 90 bars, and wherein the temperature of the injectedsteam is at least about 300° C.
 7444. The method of claim 7417, furthercomprising upgrading at least a portion of the hydrocarbons within theselected section of the formation such that a viscosity of the portionof the hydrocarbons is decreased.
 7445. The method of claim 7417,further comprising separating the recovery fluid from pyrolyzation fluidand distilled hydrocarbons in the formation, and further comprisingproducing the pyrolyzation fluid and distilled hydrocarbons.
 7446. Themethod of claim 7417, wherein the transfer fluid and vaporizedhydrocarbons are separated with membranes.
 7447. The method of claim7417, wherein the selected section comprises a first selected sectionand a second selected section and further comprising: mobilizing atleast some of the hydrocarbons within the selected first section of theformation; allowing at least some of the mobilized hydrocarbons to flowfrom the selected first section of the formation to a selected secondsection of the formation, and wherein the selected second sectioncomprises hydrocarbons; and heating at least a portion of the formationusing one or more heaters; pyrolyzing at least some of the hydrocarbonswithin the selected second section of the formation; and producing amixture from the formation.
 7448. The method of claim 7417, wherein aresidence time of the recovery fluid in the formation is greater thanabout one month and less than about six months.
 7449. The method ofclaim 7417, further comprising: allowing the recovery fluid to soak inthe selected section of the formation for a selected time period; andproducing at least a portion of the recovery fluid from the formation.7450. A method of treating hydrocarbon containing formation in situ,comprising: injecting a recovery fluid into the formation; providingheat from one or more heaters to the formation; allowing the heat totransfer from one or more of the heaters to a selected section of theformation, wherein the selected section comprises hydrocarbons;mobilizing at least some of the hydrocarbons; and producing a mixturefrom the formation, wherein the produced mixture comprises hydrocarbonshaving an average API gravity greater than about 25°.
 7451. The methodof claim 7450, wherein the heat provided from at least one of the one ormore heaters is transferred to at least a portion of the formationsubstantially by conduction.
 7452. The method of claim 7450, wherein themixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 7453. The method of claim 7450, further comprising pyrolyzingat least some of the hydrocarbons within selected section.
 7454. Themethod of claim 7450, further comprising pyrolyzing at least some of themobilized hydrocarbons.
 7455. The method of claim 7450, wherein therecovery fluid comprises water.
 7456. The method of claim 7450, whereinthe recovery fluid comprises hydrocarbons.
 7457. The method of claim7450, wherein the mixture comprises pyrolyzation fluids.
 7458. Themethod of claim 7450, wherein the mixture comprises steam.
 7459. Themethod of claim 7450, wherein a pressure is controlled such that a fluidpressure proximate to one or more of the heaters is greater than a fluidpressure proximate to a location where the fluid is produced.
 7460. Themethod of claim 7450, wherein the one or more heaters comprise at leasttwo heaters, and wherein superposition of heat from at least the twoheaters pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 7461. The method of claim 7450, wherein the heat isprovided such that an average temperature in the selected section rangesfrom approximately about 270° C. to about 375° C.
 7462. The method ofclaim 7450, further comprising: monitoring a composition of the producedmixture; and controlling a pressure in at least a portion of theformation to control the composition of the produced mixture.
 7463. Themethod of claim 7462, wherein the pressure is controlled by a valveproximate to a location where the mixture is produced.
 7464. The methodof claim 7462, wherein the pressure is controlled such that pressureproximate to one or more of the heaters is greater than a pressureproximate to a location where the mixture is produced.
 7465. The methodof claim 7450, wherein a residence time of the recovery fluid in theformation is less than about one month to greater than about six months.7466. The method of claim 7450, further comprising: allowing therecovery fluid to soak in the selected section of the formation for aselected time period; and producing at least a portion of the recoveryfluid from the formation.
 7467. A method of treating a hydrocarboncontaining formation in situ, comprising: injecting a recovery fluidinto a formation; allowing the recovery fluid to migrate through atleast a portion of the formation, wherein a size of a selected sectionincreases as a recovery fluid front migrates through an untreatedportion of the formation, and wherein the selected section is a portionof the formation treated by the recovery fluid; allowing heat from therecovery fluid to transfer heat to the selected section, wherein theheat from the recovery fluid, and heat from one or more heaters,pyrolyzes at least some of the hydrocarbons within the selected sectionof the formation; allowing the heat from the recovery fluid or one ormore heaters to mobilize at least some of the hydrocarbons at therecovery fluid front; allowing the heat from the recovery fluid, andheat from one or more heaters, to pyrolyze at least a portion of thehydrocarbons in the mobilized fluid; and producing a mixture from theformation.
 7468. The method of claim 7467, wherein the formationcomprises a heavy hydrocarbon containing formation.
 7469. The method ofclaim 7467, wherein one or more heaters are heaters.
 7470. The method ofclaim 7467, wherein the mixture is produced as a mixture of vapors.7471. The method of claim 7467, wherein the formation comprises abitumen formation.
 7472. The method of claim 7467, wherein the formationcomprises a relatively permeable formation.
 7473. The method of claim7467, wherein the formation comprises a coal formation.
 7474. The methodof claim 7467, wherein the formation comprises an oil shale formation.7475. The method of claim 7467, wherein an average temperature of theselected section is about 300° C., and wherein the recovery fluidpressure is about 90 bars.
 7476. The method of claim 7467, wherein themobilized hydrocarbons flow substantially parallel to the recovery fluidfront.
 7477. The method of claim 7467, wherein the mixture is producedfrom an upper portion of the formation.
 7478. The method of claim 7467,wherein a portion of the recovery fluid condenses and migrates due togravity to a lower portion of the selected section, and furthercomprising producing a portion of the condensed recovery fluid. 7479.The method of claim 7467, wherein the pyrolyzed fluid migrates to anupper portion of the formation.
 7480. The method of claim 7467, whereinthe mixture comprises pyrolyzation fluids.
 7481. The method of claim7467, wherein the mixture comprises recovery fluid.
 7482. The method ofclaim 7467, wherein the recovery fluid comprises steam.
 7483. The methodof claim 7467, wherein the recovery fluid is injected through one ormore injection wells.
 7484. The method of claim 7483, wherein the one ormore injection wells are located substantially horizontally in theformation.
 7485. The method of claim 7483, wherein the one or moreinjection wells are located substantially vertically in the formation.7486. The method of claim 7467, wherein the mixture is produced throughone or more production wells.
 7487. The method of claim 7486, whereinthe one or more production wells are located substantially horizontallyin the formation.
 7488. The method of claim 7467, wherein the mixture isproduced through a heater wellbore.
 7489. The method of claim 7467,wherein the produced mixture comprises hydrocarbons having an averageAPI gravity at least about 25°.
 7490. The method of claim 7467, whereinat least about 20% of the hydrocarbons in the selected first section andthe selected second section are pyrolyzed.
 7491. The method of claim7467, further comprising providing heat from one or more heaters to atleast one portion of the formation.
 7492. The method of claim 7467,wherein the heat from the one or more heaters vaporizes water injectedinto the formation.
 7493. The method of claim 7467, wherein the heatfrom the one or more heaters heats recovery fluid in the formation,wherein the recovery fluid comprises steam.
 7494. The method of claim7467, wherein the one or more heaters comprise electrical heaters. 7495.The method of claim 7467, wherein the one or more heaters comprise flamedistributed combustors.
 7495. The method of claim 7467, wherein the oneor more heaters comprise flame distributed combustors.
 7496. The methodof claim 7467, wherein the one or more heaters comprise naturaldistributed combustors.
 7497. The method of claim 7467, furthercomprising separating recovery fluid from pyrolyzation fluids in theformation.
 7498. The method of claim 7467, further comprising producingliquid hydrocarbons from the formation, and further comprisingreinjecting the produced liquid hydrocarbons into the formation. 7499.The method of claim 7467, further comprising producing a liquid mixturefrom the formation, wherein the produced liquid mixture comprisessubstantially of condensed recovery fluid.
 7500. The method of claim7467, further comprising separating condensed recovery fluid from liquidhydrocarbons in the formation, and further comprising producing thecondensed recovery fluid from the formation.
 7501. The method of claim7467, wherein the recovery fluid is injected into regions of relativelyhigh water saturation.
 7502. The method of claim 7467, wherein injectedrecovery fluid contacts a substantial portion of a volume of theselected section.
 7503. The method of claim 7467, wherein the recoveryfluid comprises steam, and wherein the pressure of the injected steam isat least about 90 bars, and wherein the temperature of the injectedsteam is at least about 300° C.
 7504. The method of claim 7467, whereinat least a portion of sulfur is retained in the formation.
 7505. Themethod of claim 7467, wherein the heat from recovery fluid partiallyupgrades at least a portion of the hydrocarbons within the selectedsection of the formation, and wherein the partial upgrading reduces theviscosity of the portion of the hydrocarbons.
 7506. The method of claim7467, further comprising separating the recovery fluid from pyrolyzationfluid and distilled hydrocarbons in the formation, and furthercomprising producing the pyrolyzation fluid and distilled hydrocarbons.7507. The method of claim 7467, wherein the recovery fluid and vaporizedhydrocarbons are separated with membranes.
 7508. The method of claim7467, wherein a residence time of the recovery fluid in the formation isless than about one month to greater than about six months.
 7509. Themethod of claim 7467, further comprising: allowing the heat transferfluid to soak in the selected section of the formation for a selectedtime period; and producing at least a portion of the heat transfer fluidfrom the formation.
 7510. A method of recovering methane from ahydrocarbon containing formation, comprising: providing heat from one ormore heaters to at least one portion of the formation, wherein theportion comprises methane; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; and producingfluids from the formation, wherein the produced fluids comprise methane.7511. The method of claim 7510, further comprising providing a barrierto at least a segment of the formation.
 7512. The method of claim 7510,further comprising: providing a refrigerant to a plurality of barrierwells to form a low temperature zone around the portion of theformation; lowering a temperature within the low temperature zone to atemperature less than about a freezing temperature of water; andremoving water from the portion of the formation.
 7513. The method ofclaim 7510, wherein an average temperature of the selected section isless than about 100° C.
 7514. The method of claim 7510, wherein anaverage temperature of the selected section is less than about a boilingpoint of water at an ambient pressure in the formation.
 7515. The methodof claim 7510, wherein an amount of methane produced from the formationis in a range from about 1 m³ of methane per ton of formation to about30 m³ of methane per ton of formation.
 7516. The method of claim 7510,wherein the methane produced from the formation is used as fuel for anin situ treatment of a hydrocarbon containing formation.
 7517. Themethod of claim 7510, wherein the methane produced from the formation isused to generate power for electrical heater wells.
 7518. The method ofclaim 7510, wherein the methane produced from the formation is used asfuel for gas fired heater wells.
 7520. The method of claim 7510, whereinthe hydrocarbon containing formation comprises a coal formation. 7521.The method of claim 7510, wherein the hydrocarbon containing formationcomprises an oil shale formation.
 7522. The method of claim 7510,wherein the fluids are produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7523. The method of claim 7510, wherein theheat provided from at least one heater is transferred to at least aportion of the formation substantially by conduction.
 7524. The methodof claim 7510, wherein the one or more of the heaters comprise heaters.7525. A method of recovering methane from a hydrocarbon containingformation, comprising: providing a barrier to a portion of theformation, wherein the portion comprises methane; removing the waterfrom the portion; and producing fluids from the formation, wherein theproduced fluids comprise methane.
 7526. The method of claim 7525,wherein the hydrocarbon containing formation comprises a coal formation.7527. The method of claim 7525, wherein the hydrocarbon containingformation comprises an oil shale formation.
 7527. The method of claim7525, wherein the hydrocarbon containing formation comprises an oilshale containing formation.
 7528. The method of claim 7525, whereinremoving water from the portion comprises pumping at least some waterfrom the formation.
 7529. The method of claim 7525, wherein the barrierinhibits migration of fluids into or out of a treatment area of theformation.
 7530. The method of claim 7525, further comprising decreasinga fluid pressure within the portion and allowing at least some of themethane to desorb.
 7531. The method of claim 7525, further comprisingproviding carbon dioxide to the portion and allowing at least some ofthe methane to desorb.
 7532. The method of claim 7525, wherein providinga barrier comprises: providing refrigerant to a plurality of freezewells to form a low temperature zone around the portion; and lowering atemperature within the low temperature zone to a temperature less thanabout a freezing temperature of water.
 7533. The method of claim 7525,wherein providing a barrier comprises providing refrigerant to aplurality of freeze wells to form a frozen barrier zone and wherein thefrozen barrier zone hydraulically isolates the treatment area from asurrounding portion of the formation.
 7534. The method of claim 7525,further comprising: providing heat from one or more heaters to at leastone portion of the formation; and allowing the heat to transfer from theone or more heaters to a selected section of the formation.
 7535. Themethod of claim 7525, wherein an average temperature of the selectedsection is less than about 100° C.
 7536. The method of claim 7525,wherein an average temperature of the selected section is less thanabout a boiling point of water at an ambient pressure in the formation.7537. A method of shutting-in an in situ treatment process in ahydrocarbon containing formation, comprising: terminating heating fromone or more heaters providing heat to a portion of the formation;monitoring a pressure in at least a portion of the formation;controlling the pressure in the portion of the formation such that thepressure is maintained approximately below a fracturing or breakthroughpressure of the formation.
 7538. The method of claim 7537, whereinmonitoring the pressure in the formation comprises detecting fractureswith passive acoustic monitoring.
 7539. The method of claim 7537,wherein controlling the pressure in the portion of the formationcomprises: producing hydrocarbon vapor from the formation when thepressure is greater than approximately the fracturing or breakthroughpressure of the formation; and allowing produced hydrocarbon vapor tooxidize at a surface of the formation.
 7540. The method of claim 7537,wherein controlling the pressure in the portion of the formationcomprises: producing hydrocarbon vapor from the formation when thepressure is greater than approximately the fracturing or breakthroughpressure of the formation; and storing at least a portion of theproduced hydrocarbon vapor.
 7541. A method of shutting-in an in situtreatment process in a hydrocarbon containing formation, comprising:terminating heating from one or more heaters providing heat to a portionof the formation; producing hydrocarbon vapor from the formation; andinjecting at least a portion of the produced hydrocarbon vapor into aportion of a storage formation.
 7542. The method of claim 7541, whereinthe storage formation comprises a spent formation.
 7543. The method ofclaim 7542, wherein an average temperature of the portion of the spentformation is less than about 100° C.
 7544. The method of claim 7542,wherein a substantial portion of condensable compounds in the injectedhydrocarbon vapor condense in the spent formation.
 7545. The method ofclaim 7541, wherein the storage formation comprises a relatively hightemperature formation, and further comprising converting a substantialportion of injected hydrocarbons into coke and molecular hydrogen. 7546.The method of claim 7545, wherein the average temperature of the portionof the relatively high temperature formation is greater than about 300°C.
 7547. The method of claim 7545, further comprising: producing atleast a portion of the H₂ from the relatively high temperatureformation; and allowing the produced molecular hydrogen to oxidize at asurface of the relatively high temperature formation.
 7550. The methodof claim 7548, wherein the depleted formation comprises a gas field.7551. The method of claim 7548, wherein the depleted formation comprisesa water zone comprising seal and trap integrity.
 7552. A method ofmining coal from a coal formation, comprising: mining coal from at leasta portion of the treated formation, wherein the treated formation isobtained by: providing heat from one or more heaters to at least aportion of the formation; allowing the heat to transfer from at leastone or more heaters to a selected section of the formation; andproducing fluids from the formation.
 7553. The method of claim 7552,wherein mining the coal comprises providing a fluid to the portion toremove at least some coal.
 7554. The method of claim 7552, wherein themined coal comprises anthracite.
 7555. The method of claim 7552, whereinmining the coal comprises mining the coal as a powder.
 7556. The methodof claim 7552, wherein mining the coal comprises mining the coal as aslurry.
 7557. The method of claim 7552, wherein the coal, beforetreatment, did not comprise a substantial quantity of anthracite, andthe mined coal comprises a substantial quantity of anthracite.
 7558. Themethod of claim 7552, wherein at least some of the mined coal comprisesa carbon content of greater than about 87 weight %.
 7557. The method ofclaim 7552, wherein the coal, before treatment, did not comprise asubstantial quantity of anthracite, and the mined coal comprises asubstantial quantity of anthracite.
 7558. The method of claim 7552,wherein at least some of the mined coal comprises a carbon content ofgreater than about 87 weight %.
 7559. The method of claim 7552, whereinat least some of the mined coal comprises a volatile matter content ofless than about 5 weight %.
 7560. The method of claim 7552, wherein atleast some of the mined coal comprises a heating value greater thanabout 25,000 kJ/kg.
 7561. The method of claim 7552, wherein at leastsome of the mined coal comprises a vitrinite reflectance of greater thanabout 2.9%.
 7562. The method of claim 7552, wherein at least somehydrocarbons in the coal have been pyrolyzed.
 7563. A method fortreating a kerogen and liquid hydrocarbon containing formation,comprising: providing heat from one or more heaters to at least oneportion of the formation; allowing the heat to transfer from the one ormore heaters to a selected section of the formation; mobilizing at leasta portion of the liquid hydrocarbons in the selected section; pyrolyzingat least a portion of the kerogen in the selected section; and producinga mixture from the formation.
 7564. The method of claim 7563, furthercomprising increasing a permeability of the selected section.
 7565. Themethod of claim 7563, further comprising increasing a permeability atleast a portion of the formation, wherein at least some of the liquidhydrocarbons in the selected section are mobilized due to the increasein the permeability in at least a portion the formation.
 7566. Themethod of claim 7563, further comprising: vaporizing at least a portionof aqueous fluids in the selected section; and increasing a permeabilityof the selected section.
 7567. The method of claim 7563, furthercomprising allowing thermal fractures to form in the formation, whereinthe thermal fractures increase the permeability of the selected section.7568. The method of claim 7563, further comprising pyrolyzing at least aportion of the mobilized liquid hydrocarbons in the selected section ofthe formation.
 7569. The method of claim 7563, wherein the one or moreheaters comprise at least two heaters, and wherein superposition of heatfrom at least two heaters pyrolyzes at least some kerogen within theselected section of the formation.
 7570. The method of claim 7563,wherein an average spacing between the one or more heaters is greaterthan about 20 m.
 7571. The method of claim 7563, wherein the mixture isproduced through one or more production wells, and wherein an averagespacing between the one or more production wells is greater than about60 m.
 7572. The method of claim 7563, wherein the mixture is producedthrough one or more production wells, and wherein an average spacingbetween production wells is greater than about 80 m.
 7573. The method ofclaim 7563, wherein the one or more heaters are placed horizontallywithin the formation.
 7574. The method of claim 7563, wherein themixture is produced through one or more production wells, wherein theone or more production wells are placed horizontally within theformation.
 7575. The method of claim 7563, wherein the one or moreheaters comprise a length of at least about 1000 m.
 7576. The method ofclaim 7563, wherein the mixture is produced through one or moreproduction wells, and wherein the one or more production wells areplaced vertically within the formation.
 7577. The method of claim 7563,wherein at least a portion of the mixture produced from the formationcomprises CO₂, and wherein the produced CO₂ is used for enhanced oilrecovery.
 7578. The method of claim 7563, wherein the liquidhydrocarbons have an API gravity of at least about 28°.
 7579. The methodof claim 7563, wherein the liquid hydrocarbons have an API gravitybetween about 10° and about 20°.
 7580. The method of claim 7563, whereinthe mixture is produced from the formation when a partial pressure ofhydrogen in at least a portion the formation is at least about 0.5 barsabsolute.
 7581. The method of claim 7563, wherein the heat provided fromat least one heater is transferred to at least a portion of theformation substantially by conduction.
 7582. The method of claim 7563,wherein the one or more of the heaters comprise heaters.
 7583. A methodof producing a soluble compound from a soluble compound containingformation, comprising: providing heat from one or more heaters to atleast a portion of a hydrocarbon containing layer; producing a mixturecomprising hydrocarbons from the formation; using heat from theformation, heat from the mixture produced from the formation, or acomponent from the mixture produced from the formation to adjust aquality of a first fluid; providing the first fluid to a solublecompound containing formation; and producing a second fluid comprising asoluble compound from the soluble compound containing formation. 7584.The method of claim 7583, further comprising pyrolyzing at least somehydrocarbons in the hydrocarbon containing layer.
 7585. The method ofclaim 7583, further comprising dissolving the soluble compound in thesoluble compound containing formation.
 7586. The method of claim 7583,wherein the soluble compound comprises a phosphate.
 7587. The method ofclaim 7583, wherein the soluble compound comprises alumina.
 7588. Themethod of claim 7583, wherein the soluble compound comprises a metal.7589. The method of claim 7583, wherein the soluble compound comprises acarbonate.
 7590. The method of claim 7583, further comprising separatingat least a portion of the soluble compound from the second fluid. 7591.The method of claim 7583, further comprising separating at least aportion of the soluble compound from the second fluid, and thenrecycling a portion of the second fluid into the soluble compoundcontaining formation.
 7592. The method of claim 7583, wherein heat isprovided from the heated formation, or from the mixture produced fromthe formation, in the form of hot water or steam.
 7593. The method ofclaim 7583, wherein the quality of the first fluid that is adjusted ispH.
 7594. The method of claim 7583, wherein the quality of the firstfluid that is adjusted is temperature.
 7595. The method of claim 7583,further comprising adding a dissolving compound to the first fluid thatfacilitates dissolution of the soluble compound in the solublecontaining formation.
 7596. The method of claim 7583, wherein CO₂produced from the hydrocarbon containing layer is used to adjust acidityof the solution.
 7597. The method of claim 7583, wherein the solublecompound containing formation is at a different depth than the portionof the hydrocarbon containing layer.
 7598. The method of claim 7583,wherein heat from the portion of the hydrocarbon containing layermigrates and heats at least a portion of the soluble compound containingformation.
 7599. The method of claim 7583, wherein the soluble compoundcontaining formation is at a different location than the portion of thehydrocarbon containing layer.
 7600. The method of claim 7583, furthercomprising using openings for providing the heaters, and furthercomprising using at least a portion of these openings to provide thefirst fluid to the soluble compound containing formation.
 7601. Themethod of claim 7583, further comprising providing the solution to thesoluble compound containing formation in one or more openings that werepreviously used to (a) provide heat to the hydrocarbon containing layer,or (b) produce the mixture from the hydrocarbon containing layer. 7602.The method of claim 7583, further comprising providing heat to thehydrocarbon containing layer, or producing the mixture from thehydrocarbon containing layer, using one or more openings that werepreviously used to provide a solution to a soluble compound containingformation.
 7603. The method of claim 7583, further comprising:separating at least a portion of the soluble compound from the secondfluid; providing heat to at least the portion of the soluble compound;and wherein the provided heat is generated in part using one or moreproducts of an in situ conversion process.
 7604. The method of claim7583, further comprising producing the second fluid when a partialpressure of hydrogen in the portion of the hydrocarbon containing layeris at least about 0.5 bars absolute.
 7605. The method of claim 7583,wherein the heat provided from at least one heater is transferred to atleast a part of the hydrocarbon containing layer substantially byconduction.
 7606. The method of claim 7583, wherein one or more of theheaters comprise heaters.
 7607. The method of claim 7583, wherein thesoluble compound containing formation comprises nahcolite.
 7608. Themethod of claim 7583, wherein greater than about 10% by weight of thesoluble compound containing formation comprises nahcolite.
 7609. Themethod of claim 7583, wherein the soluble compound containing formationcomprises dawsonite.
 7610. The method of claim 7583, wherein greaterthan about 2% by weight of the soluble compound containing formationcomprises dawsonite.
 7611. The method of claim 7583, wherein the firstfluid comprises steam.
 7612. The method of claim 7583, wherein the firstfluid comprises steam, and further comprising providing heat to thesoluble compound containing formation by injecting the steam into theformation.
 7613. The method of claim 7583, wherein the hydrocarboncontaining layer comprises oil shale.
 7614. The method of claim 7583,wherein the soluble compound containing formation is heated and then thefirst fluid is provided to the formation.
 7615. A method of treating ahydrocarbon containing formation in situ, comprising: providing heat toat least a portion of the formation; allowing the heat to transfer fromat least the portion to a selected section of the formation such thatdissociation of carbonate minerals is inhibited; injecting a first fluidinto the selected section; producing a second fluid from the formation;and conducting an in situ conversion process in the selected section.7616. The method of claim 7615, wherein the mixture is produced from theformation when a partial pressure of hydrogen in at least a portion theformation is at least about 0.5 bars absolute.
 7617. The method of claim7615, wherein the heat is provided from at least one heater, and whereinthe heat is transferred to at least the portion of the formationsubstantially by conduction.
 7618. The method of claim 7615, wherein thein situ conversion process comprises: providing additional heat to aleast a portion of the formation; pyrolyzing at least some hydrocarbonsin the portion; and producing a mixture from the formation.
 7619. Themethod of claim 7615, wherein the selected section comprises nahcolite.7620. The method of claim 7615, wherein the selected section comprisesdawsonite.
 7621. The method of claim 7615, wherein the selected sectioncomprises trona.
 7622. The method of claim 7615, wherein the selectedsection comprises gaylussite.
 7623. The method of claim 7615, whereinthe selected section comprises carbonates.
 7624. The method of claim7615, wherein the selected section comprises carbonate phosphates. 7625.The method of claim 7615, wherein the selected section comprisescarbonate chlorides.
 7626. The method of claim 7615, wherein theselected section comprises silicates.
 7627. The method of claim 7615,wherein the selected section comprises borosilicates.
 7628. The methodof claim 7615, wherein the selected section comprises halides.
 7629. Themethod of claim 7615, wherein the first fluid comprises a pH greaterthan about
 7. 7630. The method of claim 7615, wherein the first fluidcomprises a temperature less than about 110° C.
 7631. The method ofclaim 7615, wherein the portion has previously undergone an in situconversion process prior to the injection of the first fluid.
 7632. Themethod of claim 7615, wherein the second fluid comprises hydrocarbons.7633. The method of claim 7615, wherein the second fluid compriseshydrocarbons, and further comprising: fragmenting at least some of theportion prior to providing the first fluid; generating hydrocarbons; andproviding at least some of the second fluid to a surface treatment unit,wherein the second fluid comprises at least some of the generatedhydrocarbons.
 7634. The method of claim 7615, further comprisingremoving mass from the selected section in the second fluid.
 7635. Themethod of claim 7615, further comprising removing mass from the selectedsection in the second fluid such that a permeability of the selectedsection increases.
 7636. The method of claim 7615, further comprisingremoving mass from the selected section in the second fluid anddecreasing a heat transfer time in the selected section.
 7637. Themethod of claim 7615, further comprising controlling the heat such thatthe selected section has a temperature of above about 120° C.
 7638. Themethod of claim 7615, wherein the selected section comprises nahcolite,and further comprising controlling the heat such that the selectedsection has a temperature less than about a dissociation temperature ofnahcolite.
 7639. The method of claim 7615, wherein the second fluidcomprises soda ash, and further comprising removing at least a portionof the soda ash from the second fluid as sodium carbonate.
 7640. Themethod of claim 7615, wherein the in situ conversion process comprisespyrolyzing hydrocarbon containing material in the selected section.7641. The method of claim 7615, wherein the second fluid comprisesnahcolite, and further comprising: separating at least a portion of thenahcolite from the second fluid; providing heat to at least some of theseparated nahcolite to form a sodium carbonate solution; providing atleast some of the sodium carbonate solution to at least the portion ofthe formation; and producing a third fluid comprising alumina from theformation.
 7642. The method of claim 7615, further comprising providinga barrier to at least the portion of the formation to inhibit migrationof fluids into or out of the portion.
 7643. The method of claim 7615,further comprising controlling the heat such that a temperature withinthe selected section of the portion is less than about 100° C.
 7644. Themethod of claim 7615, further comprising: pyrolyzing at least somehydrocarbons within the selected section of the formation; producing amixture from the formation; reducing a temperature of the selectedsection of the formation; injecting a third fluid into the selectedsection; and producing a fourth fluid from the formation.
 7645. Themethod of claim 7644, wherein the third fluid comprises water.
 7646. Themethod of claim 7644, wherein the third fluid comprises steam.
 7647. Themethod of claim 7644, wherein the fourth fluid comprises a metal. 7648.The method of claim 7644, wherein the fourth fluid comprises a mineral.7649. The method of claim 7644, wherein the fourth fluid comprisesaluminum.
 7650. The method of claim 7644, wherein the fourth fluidcomprises a metal, and further comprising producing the metal from thesecond fluid.
 7651. The method of claim 7644, further comprisingproducing a non-hydrocarbon material from the fourth fluid.
 7652. Themethod of claim 7615, wherein the first fluid comprises steam.
 7653. Themethod of claim 7615, wherein the second fluid comprises a metal. 7654.The method of claim 7615, wherein the second fluid comprises a mineral.7655. The method of claim 7615, wherein the second fluid comprisesaluminum.
 7654. The method of claim 7615, wherein the second fluidcomprises a mineral.
 7655. The method of claim 7615, wherein the secondfluid comprises aluminum.
 7656. The method of claim 7615, wherein thesecond fluid comprises a metal, and further comprising separating themetal from the second fluid.
 7657. The method of claim 7615, furthercomprising producing a non-hydrocarbon material from the second fluid.7658. The method of claim 7615, wherein greater than about 10% by weightof the selected section comprises nahcolite.
 7659. The method of claim7615, wherein greater than about 2% by weight of the selected sectioncomprises dawsonite.
 7660. The method of claim 7615, wherein theprovided heat comprises waste heat from another portion of theformation.
 7661. The method of claim 7615, wherein the first fluidcomprises steam, and further comprising providing heat to the formationby injecting the steam into the formation.
 7662. The method of claim7615, further comprising providing heat to the formation by injectingthe first fluid into the formation.
 7663. The method of claim 7615,further comprising providing heat to the formation by injecting thefirst fluid into the formation, wherein the first fluid is at atemperature above about 90° C.
 7664. The method of claim 7615, furthercomprising controlling a temperature of the selected section whileinjecting the first fluid, wherein the temperature is less than about atemperature at which nahcolite will dissociate.
 7665. The method ofclaim 7615, wherein a temperature within the selected section is lessthan about 90° C. prior to injecting the first fluid to the formation.7666. The method of claim 7615, wherein the hydrocarbon containingformation comprises oil shale.
 7667. The method of claim 7615, furthercomprising providing a barrier substantially surrounding the selectedsection such that the barrier inhibits the flow of water into theformation.
 7668. A method of treating a hydrocarbon containing formationin situ, comprising: injecting a first fluid into the selected section;producing a second fluid from the formation; providing heat from one ormore heaters to at least a portion of the formation, wherein the heat isprovided after production of the second fluid has begun; allowing theheat to transfer from at least a portion of the formation; pyrolyzing atleast some hydrocarbons within the selected section; and producing amixture from the formation.
 7669. The method of claim 7668, wherein theselected section comprises nahcolite.
 7670. The method of claim 7668,wherein the selected section comprises dawsonite.
 7671. The method ofclaim 7668, wherein the selected section comprises trona.
 7672. Themethod of claim 7668, wherein the selected section comprises gaylussite.7673. The method of claim 7668, wherein the selected section comprisescarbonates.
 7674. The method of claim 7668, wherein the selected sectioncomprises carbonate phosphates.
 7675. The method of claim 7668, whereinthe selected section comprises carbonate chlorides.
 7676. The method ofclaim 7668, wherein the selected section comprises silicates.
 7677. Themethod of claim 7668, wherein the selected section comprisesborosilicates.
 7678. The method of claim 7668, wherein the selectedsection comprises halides.
 7679. The method of claim 7668, wherein thefirst fluid comprises a pH greater than about
 7. 7680. The method ofclaim 7668, wherein the first fluid comprises a temperature less thanabout 110° C.
 7681. The method of claim 7668, wherein the second fluidcomprises hydrocarbons.
 7682. The method of claim 7668, wherein thesecond fluid comprises hydrocarbons, and further comprising: fragmentingat least some of the portion prior to providing the first fluid;generating hydrocarbons; and providing at least some of the second fluidto a surface treatment unit, wherein the second fluid comprises at leastsome of the generated hydrocarbons.
 7683. The method of claim 7668,further comprising removing mass from the selected section in the secondfluid.
 7684. The method of claim 7668, further comprising removing massfrom the selected section in the second fluid such that a permeabilityof the selected section increases.
 7685. The method of claim 7668,further comprising removing mass from the selected section in the secondfluid and decreasing a heat transfer time in the selected section. 7686.The method of claim 7668, further comprising controlling the heat suchthat the selected section has a temperature of above about 270° C. 7687.The method of claim 7668, wherein the second fluid comprises soda ash,and further comprising removing at least a portion of the soda ash fromthe second fluid as sodium carbonate.
 7688. The method of claim 7668,wherein the second fluid comprises nahcolite, and further comprising:separating at least a portion of the nahcolite from the second fluid;providing heat to at least some of the separated nahcolite to form asodium carbonate solution; providing at least some of the sodiumcarbonate solution to at least the portion of the formation; andproducing a third fluid comprising alumina from the formation.
 7689. Themethod of claim 7668, further comprising providing a barrier to at leastthe portion of the formation to inhibit migration of fluids into or outof the portion.
 7690. The method of claim 7668, wherein the first fluidcomprises steam.
 7691. The method of claim 7668, wherein the secondfluid comprises a metal.
 7692. The method of claim 7668, wherein thesecond fluid comprises a mineral.
 7693. The method of claim 7668,wherein the second fluid comprises aluminum.
 7694. The method of claim7668, wherein the second fluid comprises a metal, and further comprisingseparating the metal from the second fluid.
 7695. The method of claim7668, further comprising producing a non-hydrocarbon material from thesecond fluid.
 7696. The method of claim 7668, wherein greater than about10% by weight of the selected section comprises nahcolite.
 7697. Themethod of claim 7668, wherein greater than about 2% by weight of theselected section comprises dawsonite.
 7698. The method of claim 7668,wherein at least some of the provided heat comprises waste heat fromanother portion of the formation.
 7699. The method of claim 7668,wherein the first fluid comprises steam, and further comprisingproviding heat to the formation by injecting the steam into theformation.
 7700. The method of claim 7668, further comprising providingheat to the formation by injecting the first fluid into the formation.7701. The method of claim 7668, further comprising providing heat to theformation by injecting the first fluid into the formation, wherein thefirst fluid is at a temperature above about 90° C.
 7702. The method ofclaim 7668, further comprising controlling a temperature of the selectedsection while injecting the first fluid, wherein the temperature is lessthan about a temperature at which nahcolite will dissociate.
 7704. Themethod of claim 7668, further comprising providing a barriersubstantially surrounding the selected section such that the barrierinhibits the flow of water into the formation.
 7705. The method of claim7668, wherein the mixture is produced from the formation when a partialpressure of hydrogen in at least a portion the formation is at leastabout 0.5 bars absolute.
 7706. The method of claim 7668, wherein theheat provided from at least one heater is transferred to at least aportion of the formation substantially by conduction.
 7707. The methodof claim 7668, wherein the one or more of the heaters comprise heaters.7708. A method of solution mining alumina from an in situ hydrocarboncontaining formation, comprising: providing heat from one or moreheaters to a least a portion of the formation; pyrolyzing at least somehydrocarbons in the portion; and producing a mixture from the formation;providing a brine solution to a portion of the formation; and producinga mixture comprising alumina from the formation.
 7709. The method ofclaim 7708, wherein the selected section comprises dawsonite.
 7710. Themethod of claim 7708, further comprising: separating at least a portionof the alumina from the mixture; and providing heat to at least theportion of the alumina to generate aluminum.
 7711. The method of claim7708, further comprising: separating at least a portion of the aluminafrom the mixture;
 7711. The method of claim 7708, further comprising:separating at least a portion of the alumina from the mixture; providingheat to at least the portion of the alumina to generate aluminum; andwherein the provided heat is generated in part using one or moreproducts of an in situ conversion process.
 7712. The method of claim7708, further comprising producing the mixture when a partial pressureof hydrogen in the formation is at least about 0.5 bars absolute. 7713.The method of claim 7708, wherein the heat provided from at least oneheater is transferred to at least a portion of the formationsubstantially by conduction.
 7714. The method of claim 7708, wherein oneor more of the heaters comprise heaters.
 7715. A method of treating ahydrocarbon containing formation in situ, comprising: allowing atemperature of a portion of the formation to decrease, wherein theportion has previously undergone an in situ conversion process;injecting a first fluid into the selected section; and producing asecond fluid from the formation.
 7716. The method of claim 7715, whereinthe in situ conversion process comprises: providing heat to a least aportion of the formation; pyrolyzing at least some hydrocarbons in theportion; and producing a mixture from the formation.
 7717. The method ofclaim 7715, wherein the first fluid comprises water.
 7718. The method ofclaim 7715, wherein the second fluid comprises a metal.
 7719. The methodof claim 7715, wherein the second fluid comprises a mineral.
 7720. Themethod of claim 7715, wherein the second fluid comprises aluminum. 7721.The method of claim 7715, wherein the second fluid comprises a metal,and further comprising producing the metal from the second fluid. 7722.The method of claim 7715, further comprising producing a non-hydrocarbonmaterial from the second fluid.
 7723. The method of claim 7715, whereinthe selected section comprises nahcolite.
 7724. The method of claim7715, wherein greater than about 10% by weight of the selected sectioncomprises nahcolite.
 7725. The method of claim 7715, wherein theselected section comprises dawsonite.
 7726. The method of claim 7715,wherein greater than about 2% by weight of the selected sectioncomprises dawsonite.
 7727. The method of claim 7715, wherein theprovided heat comprises waste heat from another portion of theformation.
 7728. The method of claim 7715, wherein the first fluidcomprises steam.
 7729. The method of claim 7715, wherein the first fluidcomprises steam, and further comprising providing heat to the formationby injecting the steam into the formation.
 7730. The method of claim7715, further comprising providing heat to the formation by injectingthe first fluid into the formation.
 7731. The method of claim 7715,further comprising providing heat to the formation by injecting thefirst fluid into the formation, wherein the first fluid is at atemperature above about 90° C.
 7732. The method of claim 7715, whereinthe reduced temperature of the selected section is less than about 90°C.
 7733. The method of claim 7715, wherein an average richness of atleast the portion of the selected section is greater than about 0.10liters per kilogram.
 7734. The method of claim 7715, wherein thehydrocarbon containing formation comprises oil shale.
 7735. A method fortreating a relatively permeable formation in situ, comprising: providingheat from one or more heaters to a first section of the formation suchthat the heat provided to the first section pyrolyzes at least somehydrocarbons within the first section; providing heat from one or moreheaters to a second section of the formation such that the heat providedto the second section pyrolyzes at least some hydrocarbons within thesecond section; inducing at least a portion of the hydrocarbons from thesecond section to flow into the first section; and producing a mixturefrom the first section, wherein the produced mixture comprises at leastsome pyrolyzed hydrocarbons from the second section.
 7736. The method ofclaim 7735, wherein a portion of the first section comprises a firstpermeability, wherein a portion of the second section comprises a secondpermeability, and wherein the first permeability is greater than aboutthe second permeability.
 7737. The method of claim 7735, wherein aportion of the first section comprises a first permeability, wherein aportion of the second section comprises a second permeability, andwherein the first permeability is less than about the secondpermeability.
 7738. The method of claim 7735, wherein the second sectionis substantially adjacent to the first section.
 7739. The method ofclaim 7735, further comprising providing heat to a third section of theformation such that the heat provided to the third section pyrolyzes atleast some hydrocarbons in the third section and inducing a portion ofthe hydrocarbons from the third section to flow into the first section.7740. The method of claim 7739, wherein the third section issubstantially adjacent to the first section.
 7741. The method of claim7735, further comprising: providing heat from one or more heaters to athird section of the formation such that the heat provided to the thirdsection pyrolyzes at least some hydrocarbons in the third section; andinducing a portion of the hydrocarbons from the third section to flowinto the first section through the second section.
 7742. The method ofclaim 7741, wherein the third section is substantially adjacent to thesecond section.
 7743. The method of claim 7735, further comprisingmaintaining a pressure in the formation below about 150 bars absolute.7744. The method of claim 7735, further comprising inhibiting productionof the produced mixture until at least some hydrocarbons in theformation have been pyrolyzed.
 7745. The method of claim 7735, furthercomprising producing at least some hydrocarbons from the first sectionbefore providing heat to the second section.
 7746. The method of claim7735, further comprising producing at least some hydrocarbons from thefirst section before a temperature in the second section reaches apyrolysis temperature.
 7747. The method of claim 7735, furthercomprising maintaining a pressure within the formation below a selectedpressure by producing at least some hydrocarbons from the formation.7748. The method of claim 7735, further comprising producing theproduced mixture through at least one production well in or proximatethe first section.
 7749. The method of claim 7735, further comprisingproducing at least some hydrocarbons through at least one productionwell in or proximate the second section.
 7750. The method of claim 7735,further comprising controlling the heat provided to the first sectionand the second section such that conversion of heavy hydrocarbons intolight hydrocarbons within the formation is controlled.
 7751. The methodof claim 7750, wherein controlling the heat provided to the firstsection and the second section comprises adjusting heat output of atleast one of the heaters that heats the first section.
 7752. The methodof claim 7750, wherein controlling the heat provided to the firstsection and the second section comprises adjusting heat output of atleast one of the heaters that heats the second section.
 7753. The methodof claim 7735, wherein one or more heaters provide heat to the firstsection of the formation and the second section of the formation. 7754.The method of claim 7735, wherein a first set of one or more heatersprovides heat to the first section and a second set of one or moreheaters provides heat to the second section.
 7755. The method of claim7735, further comprising controlling the heat provided to the firstsection and the second section to produce a desired characteristic inthe produced mixture.
 7756. The method of claim 7755, whereincontrolling the heat provided to the first section and the secondsection comprises adjusting heat output of at least one of the heatersthat heats the first section.
 7757. The method of claim 7755, whereincontrolling the heat provided to the first section and the secondsection comprises adjusting heat output of at least one of the heatersthat heats the first section.
 7758. The method of claim 7755, whereinthe desired characteristic in the produced mixture comprises an APIgravity of the produced mixture.
 7759. The method of claim 7755, whereinthe desired characteristic in the produced mixture comprises aproduction rate of the produced mixture.
 7760. The method of claim 7755,wherein the desired characteristic in the produced mixture comprises aweight percentage of light hydrocarbons in the produced mixture. 7761.The method of claim 7735, wherein the produced mixture comprises an APIgravity of greater than about 20°.
 7762. The method of claim 7735,wherein the produced mixture comprises an acid number less than about 1.7763. The method of claim 7735, wherein greater than about 50% by weightof the initial mass of hydrocarbons in the formation is produced. 7764.The method of claim 7735, wherein at least a portion of the firstsection is above a pyrolysis temperature of the hydrocarbons.
 7765. Themethod of claim 7764, wherein the pyrolysis temperature is at leastabout 250° C.
 7766. The method of claim 7735, wherein the heaters thatheat the first section comprise a spacing between heated portions of theheaters of less than about 25 m.
 7767. The method of claim 7735, furthercomprising producing the mixture when a partial pressure of hydrogen inthe formation is at least about 0.5 bars absolute.
 7768. The method ofclaim 7735, wherein the heat provided from at least one heater istransferred to at least a portion of the formation substantially byconduction.
 7769. The method of claim 7735, wherein one or more of theheaters comprise heaters.
 7770. The method of claim 7735, wherein aratio of energy output of the produced mixture to energy input into theformation is at least about
 5. 7771. A method for treating a relativelypermeable formation in situ, comprising: providing heat from one or moreheaters to a first section of the formation such that the heat providedto the first section pyrolyzes at least some hydrocarbons within thefirst section; providing heat from one or more heaters to a secondsection of the formation such that the heat provided to the secondsection pyrolyzes at least some hydrocarbons within the second section;inducing at least a portion of the hydrocarbons from the second sectionto flow into the first section; inhibiting production of a mixture untilat least some hydrocarbons in the formation have been pyrolyzed; andproducing the mixture from the first section, wherein the producedmixture comprises at least some pyrolyzed hydrocarbons from the secondsection.
 7772. A method for treating a relatively permeable formation insitu, comprising: providing heat from one or more heaters to a firstsection of the formation such that the heat provided to the firstsection reduces the viscosity of at least some heavy hydrocarbons withinthe first section; providing heat from one or more heaters to a secondsection of the formation such that the heat provided to the secondsection reduces the viscosity of at least some heavy hydrocarbons withinthe second section; inducing a portion of the heavy hydrocarbons fromthe second section to flow into the first section; pyrolyzing at leastsome of the heavy hydrocarbons within the first section; and producing amixture from the first section, wherein the produced mixture comprisesat least some pyrolyzed hydrocarbons.
 7773. The method of claim 7772,wherein the second section is substantially adjacent to the firstsection.
 7774. The method of claim 7772, further comprising producing amixture from the first section of the formation, wherein the mixturecomprises at least some heavy hydrocarbons.
 7775. The method of claim7772, further comprising producing the mixture from the first sectionthrough a production well in or proximate the first section andpyrolyzing at least some of the heavy hydrocarbons within the productionwell.
 7776. The method of claim 7772, further comprising pyrolyzing atleast some hydrocarbons within the second section.
 7777. The method ofclaim 7772, further comprising providing heat to a third section of theformation such that the heat provided to the third section reduces theviscosity of at least some heavy hydrocarbons in the third section, andinducing a portion of the heavy hydrocarbons from the third section toflow into the first section.
 7778. The method of claim 7777, wherein thethird section is substantially adjacent to the first section.
 7779. Themethod of claim 7772, further comprising: providing heat from one ormore heaters to a third section of the formation such that the heatprovided to the third section reduces the viscosity of at least someheavy hydrocarbons in the third section; inducing a portion of the heavyhydrocarbons from the third section to flow into the second section;pyrolyzing at least some of the heavy hydrocarbons within the secondsection; and producing a mixture from the second section, wherein theproduced mixture comprises at least some pyrolyzed hydrocarbons. 7780.The method of claim 7779, wherein the third section is substantiallyadjacent to the second section.
 7781. The method of claim 7772, furthercomprising: providing heat from one or more heaters to a third sectionof the formation such that the heat provided to the third sectionreduces the viscosity of at least some heavy hydrocarbons in the thirdsection; and inducing a portion of the heavy hydrocarbons from the thirdsection to flow into the first section through the second section. 7782.The method of claim 7781, wherein the third section is substantiallyadjacent to the second section.
 7783. The method of claim 7772, whereinone or more heaters provide heat to the first section of the formationand the second section of the formation.
 7784. The method of claim 7772,wherein a first set of one or more heaters provides heat to the firstsection and a second set of one or more heaters provides heat to thesecond section.
 7785. The method of claim 7772, further comprisingcontrolling the heat provided to the first section and the secondsection such that conversion of heavy hydrocarbons into lighthydrocarbons within the first section is controlled.
 7786. The method ofclaim 7785, wherein controlling the heat provided to the first sectionand the second section comprises adjusting heat output of at least oneof the heaters that heats the first section.
 7787. The method of claim7785, wherein controlling the heat provided to the first section and thesecond section comprises adjusting heat output of at least one of theheaters that heats the second section.
 7788. The method of claim 7772,further comprising controlling the heat provided to the first sectionand the second section to produce a desired characteristic in theproduced mixture.
 7789. The method of claim 7788, wherein controllingthe heat provided to the first section and the second section comprisesadjusting heat output of at least one of the heaters that heats thefirst section.
 7790. The method of claim 7788, wherein controlling theheat provided to the first section and the second section comprisesadjusting heat output of at least one of the heaters that heats thefirst section.
 7791. The method of claim 7788, wherein the desiredcharacteristic in the produced mixture comprises an API gravity of theproduced mixture.
 7792. The method of claim 7788, wherein the desiredcharacteristic in the produced mixture comprises a weight percentage oflight hydrocarbons in the produced mixture.
 7793. The method of claim7772, further comprising producing at least about 70% of an initialvolume in place from the formation.
 7794. The method of claim 7772,wherein the produced mixture comprises an API gravity of greater thanabout 20°.
 7795. The method of claim 7772, wherein the produced mixturecomprises an acid number less than about
 1. 7796. The method of claim7772, wherein at least a portion of the first section is above apyrolysis temperature of the hydrocarbons.
 7797. The method of claim7796, wherein the pyrolysis temperature is at least about 250° C. 7798.The method of claim 7772, wherein a spacing between heated sections ofat least two heaters is less than about 25 m.
 7799. The method of claim7772, further comprising producing the mixture when a partial pressureof hydrogen in the formation is at least about 0.5 bars absolute. 7800.The method of claim 7772, wherein the heat provided from at least oneheater is transferred to at least a portion of the formationsubstantially by conduction.
 7801. The method of claim 7772, wherein oneor more of the heaters comprise heaters.
 7802. The method of claim 7772,wherein a ratio of energy output of the produced mixture to energy inputinto the formation is at least about
 5. 7803. A method for treating arelatively permeable formation in situ, comprising: providing heat to atleast a portion of the formation; producing heavy hydrocarbons from afirst section of the relatively permeable formation; inducing heavyhydrocarbons from a second section of the formation to flow into thefirst section of the formation; producing a portion of the secondsection heavy hydrocarbons from the first section of the formation;inducing heavy hydrocarbons from a third section of the formation toflow into the second section of the formation; and producing a portionof the third section heavy hydrocarbons from the second section of theformation or the first section of the formation.
 7804. The method ofclaim 7803, wherein greater than 50% by weight of the initial mass ofhydrocarbons in a portion of the formation selected for treatment areproduced
 7805. The method of claim 7803, further comprising pyrolyzingat least some of the second section heavy hydrocarbons in the firstsection.
 7806. The method of claim 7803, further comprising pyrolyzingat least some of the third section heavy hydrocarbons in the secondsection or the first section.
 7807. The method of claim 7803, furthercomprising producing at least about 70% of an initial volume in placefrom the formation.
 7808. The method of claim 7803, further comprisingproducing hydrocarbons when a partial pressure of hydrogen in theformation is at least about 0.5 bars absolute.
 7809. The method of claim7803, wherein the heat provided from at least one heater is transferredto at least a portion of the formation substantially by conduction.7810. The method of claim 7803, wherein one or more of the heaterscomprise heaters.
 7811. A method for treating a relatively permeableformation in situ, comprising: providing heat from one or more heatersto at least a portion of the relatively permeable formation; allowingthe heat to transfer from the one or more heaters to a selected sectionof the formation such that the heat reduces the viscosity of at leastsome hydrocarbons within the selected section; providing a gas to theselected section of the formation, wherein the gas produces a flow of atleast some hydrocarbons within the selected section; and producing amixture from the selected section.
 7812. The method of claim 7811,further comprising controlling a pressure within the selected sectionsuch that the pressure is maintained below about 150 bars absolute.7813. The method of claim 7811, further comprising controlling atemperature within the selected section to maintain the temperaturewithin the selected section below a pyrolysis temperature of thehydrocarbons.
 7814. The method of claim 7813, further comprisingmaintaining an average temperature within the selected section aboveabout 50° C. and below about 210° C.
 7815. The method of claim 7811,wherein providing the gas to the selected section comprises injectingthe gas such that the gas sweeps hydrocarbons within the selectedsection, and wherein greater than about 50% by weight of the initialmass of hydrocarbons is produced from the selected section.
 7816. Themethod of claim 7811, further comprising producing at least about 70% ofan initial volume in place from the selected section.
 7817. The methodof claim 7811, wherein a ratio of energy output of the produced mixtureto energy input into the formation is at least about
 5. 7818. The methodof claim 7811, wherein a ratio of energy output of the produced mixtureto energy input into the formation is at least about 5, and wherein theproduced mixture comprises an API gravity of at least about
 15. 7819.The method of claim 7811, further comprising providing the gas throughone or more injection wells in the selected section.
 7820. The method ofclaim 7811, further comprising providing the gas through one or moreinjection wells in the selected section and controlling a pressurewithin the selected section by controlling an injection rate into atleast one injection well.
 7821. The method of claim 7811, furthercomprising providing the gas through one or more injection wells in theformation and controlling a pressure within the selected section bycontrolling a location for injecting the gas within the formation. 7822.The method of claim 7811, further comprising producing the mixturethrough one or more production wells in or proximate the formation.7823. The method of claim 7811, further comprising controlling apressure within the selected section through one or more productionwells in or proximate the formation.
 7824. The method of claim 7811,further comprising controlling a temperature within the selected sectionwhile controlling a pressure within the selected section.
 7825. Themethod of claim 7811, further comprising creating a path for flow ofhydrocarbons along a length of at least one heater in the selectedsection.
 7826. The method of claim 7825, wherein the path along thelength of at least one heater extends between an injection well and aproduction well.
 7827. The method of claim 7825, wherein a heater isturned off after the path for flow along the heater is created. 7828.The method of claim 7811, wherein the gas increases a flow ofhydrocarbons within the formation.
 7829. The method of claim 7811,further comprising increasing a pressure in the selected section withthe provided gas.
 7830. The method of claim 7811, wherein a spacingbetween heated sections of at least two sources is less than about 50 mand greater than about 5 m.
 7831. The method of claim 7811, wherein thegas comprises carbon dioxide.
 7832. The method of claim 7811, whereinthe gas comprises nitrogen.
 7833. The method of claim 7811, wherein thegas comprises steam.
 7834. The method of claim 7811, wherein the gascomprises water, and wherein the water forms steam in the formation.7835. The method of claim 7811, wherein the gas comprises methane. 7836.The method of claim 7811, wherein the gas comprises gas produced fromthe formation.
 7837. The method of claim 7811, further comprisingproviding the gas through at least one injection well placedsubstantially vertically in the formation, and producing the mixturethrough a heater placed substantially horizontally in the formation.7838. The method of claim 7837, further comprising selectively limitinga temperature proximate a selected portion of a wellbore of the heaterto inhibit coke formation at or near the selected portion, and producingthe mixture through perforations in the selected portion of thewellbore.
 7839. The method of claim 7811, further comprising allowingheat to transfer to the selected section such that the provided heatpyrolyzes at least some hydrocarbons within the selected section. 7840.The method of claim 7811, further comprising controlling the transfer ofheat from the one or more heaters and controlling the flow of providedgas such that the flow of hydrocarbons within the selected section iscontrolled.
 7841. The method of claim 7811, further comprising producingthe mixture when a partial pressure of hydrogen in the formation is atleast about 0.5 bars absolute.
 7842. The method of claim 7811, whereinthe heat provided from at least one heater is transferred to at least aportion of the formation substantially by conduction.
 7843. The methodof claim 7811, wherein one or more of the heaters comprise heaters.7844. The method of claim 7811, wherein the produced mixture comprisesan acid number less than about
 1. 7845. A method for treating arelatively permeable formation in situ, comprising: providing heat fromone or more heaters to at least a portion of the relatively permeableformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation such that the heat reduces theviscosity of at least some hydrocarbons within the selected section;providing a gas to the selected section of the formation, wherein thegas produces a flow of at least some hydrocarbons within the selectedsection; controlling a pressure within the selected section such thatthe pressure is maintained below about 150 bars absolute; and producinga mixture from the selected section.
 7846. A method for treating arelatively permeable formation in situ, comprising: providing heat fromone or more heaters to at least a portion of the relatively permeableformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation such that the heat pyrolyzes atleast some hydrocarbons within the selected section; producing a mixtureof hydrocarbons from the selected section; and controlling production ofthe mixture to adjust the time that at least some hydrocarbons areexposed to pyrolysis temperatures in the formation in order to producehydrocarbons of a selected quality in the mixture.
 7847. The method ofclaim 7846, further comprising inhibiting production of hydrocarbonsfrom the formation until at least some hydrocarbons have been pyrolyzed.7848. The method of claim 7846, wherein the selected quality comprises aselected minimum API gravity.
 7849. The method of claim 7846, whereinthe selected quality comprises an API gravity of at least about 20°.7850. The method of claim 7846, wherein the selected quality comprises aselected maximum weight percentage of heavy hydrocarbons.
 7851. Themethod of claim 7846, wherein the selected quality comprises a meancarbon number that is less than
 12. 7852. The method of claim 7846,wherein the produced mixture comprises an acid number less than about 1.7853. The method of claim 7846, further comprising sampling a teststream of the produced mixture to determine the selected quality of theproduced mixture.
 7854. The method of claim 7846, further comprisingdetermining the time that at least some hydrocarbons in the producedmixture are subjected to pyrolysis temperatures using laboratorytreatment of formation samples.
 7855. The method of claim 7846, furthercomprising determining the time that at least some hydrocarbons in theproduced mixture are subjected to pyrolysis temperatures using acomputer simulation of treatment of the formation.
 7856. The method ofclaim 7846, further comprising controlling a pressure within theselected section such that the pressure is maintained below alithostatic pressure of the formation.
 7857. The method of claim 7846,further comprising controlling a pressure within the selected sectionsuch that the pressure is maintained below a hydrostatic pressure of theformation.
 7858. The method of claim 7846, further comprisingcontrolling a pressure within the selected section such that thepressure is maintained below about 150 bars absolute.
 7859. The methodof claim 7846, further comprising controlling a pressure within theselected section through one or more production wells.
 7860. The methodof claim 7846, further comprising controlling a pressure within theselected section through one or more pressure release wells.
 7861. Themethod of claim 7846, further comprising controlling a pressure withinthe selected section by producing at least some hydrocarbons from theselected section.
 7862. The method of claim 7846, further comprisingproducing the mixture when a partial pressure of hydrogen in theformation is at least about 0.5 bars absolute.
 7863. The method of claim7846, wherein the heat provided from at least one heater is transferredto at least a portion of the formation substantially by conduction.7864. The method of claim 7846, wherein one or more of the heaterscomprise heaters.
 7865. The method of claim 7846, wherein a ratio ofenergy output of the produced mixture to energy input into the formationis at least about
 5. 7866. A method for treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heaters to at least a portion of the formation; allowing the heatto transfer from the one or more heaters to a selected section of theformation such that the heat pyrolyzes at least some hydrocarbons withinthe selected section; selectively limiting a temperature proximate aselected portion of a heater wellbore to inhibit coke formation at ornear the selected portion; and producing at least some hydrocarbonsthrough the selected portion of the heater wellbore.
 7867. The method ofclaim 7866, further comprising generating water in the selected portionto inhibit coke formation at or near the selected portion of the heaterwellbore.
 7868. The method of claim 7866, wherein the heater wellbore isplaced substantially horizontally within the selected section.
 7869. Themethod of claim 7866, wherein selectively limiting the temperaturecomprises providing less heat at the selected portion of the heaterwellbore than other portions of the heater wellbore in the selectedsection.
 7870. The method of claim 7866, wherein selectively limitingthe temperature comprises maintaining the temperature proximate theselected portion below pyrolysis temperatures.
 7871. The method of claim7866, further comprising producing a mixture from the selected sectionthrough a production well.
 7872. The method of claim 7866, furthercomprising providing at least some heat to an overburden section of theheater wellbore to maintain the produced hydrocarbons in a vapor phase.7873. The method of claim 7866, further comprising maintaining apressure in the selected section below about 150 bars absolute. 7874.The method of claim 7866, further comprising producing hydrocarbons whena partial pressure of hydrogen in the formation is at least about 0.5bars absolute.
 7875. The method of claim 7866, wherein the heat providedfrom at least one heater is transferred to at least a portion of theformation substantially by conduction.
 7876. The method of claim 7866,wherein one or more of the heaters comprise heaters.
 7877. The method ofclaim 7866, wherein a ratio of energy output of the produced mixture toenergy input into the formation is at least about
 5. 7878. The method ofclaim 7866, wherein the produced mixture comprises an acid number lessthan about
 1. 7879. A method for treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatersto at least a portion of the formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation suchthat the heat pyrolyzes at least some hydrocarbons within the selectedsection; controlling operating conditions at a production well toinhibit coking in or proximate the production well; and producing amixture from the selected section through the production well.
 7880. Themethod of claim 7879, wherein controlling the operating conditions atthe production well comprises controlling heat output from at least oneheater proximate the production well.
 7881. The method of claim 7879,wherein controlling the operating conditions at the production wellcomprises reducing or turning off heat provided from at least one of theheaters for at least part of a time in which the mixture is producedthrough the production well.
 7882. The method of claim 7879, whereincontrolling the operating conditions at the production well comprisesincreasing or turning on heat provided from at least one of the heatersto maintain a desired quality in the produced mixture.
 7883. The methodof claim 7879, wherein controlling the operating conditions at theproduction well comprises producing the mixture at a locationsufficiently spaced from at least one heater such that coking isinhibited at the production well.
 7884. The method of claim 7879,further comprising adding steam to the selected section to inhibitcoking at the production well.
 7885. The method of claim 7879, furthercomprising producing the mixture when a partial pressure of hydrogen inthe formation is at least about 0.5 bars absolute.
 7886. The method ofclaim 7879, wherein the heat provided from at least one heater istransferred to at least a portion of the formation substantially byconduction.
 7887. The method of claim 7879, wherein one or more of theheaters comprise heaters.
 7888. The method of claim 7879, wherein aratio of energy output of the produced mixture to energy input into theformation is at least about
 5. 7889. The method of claim 7879, whereinthe produced mixture comprises an acid number less than about
 1. 7890. Amethod for treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heaters to at least aportion of the hydrocarbon containing formation; allowing the heat totransfer from the one or more heaters to a selected section of theformation such that the heat pyrolyzes at least some hydrocarbons withinthe selected section; producing a mixture from the selected section; andcontrolling a quality of the produced mixture by varying a location forproducing the mixture.
 7891. The method of claim 7890, wherein varyingthe location for producing the mixture comprises varying a productionlocation within a production well in or proximate the selected section.7892. The method of claim 7891, wherein varying the production locationwithin the production well comprises varying a packing height within theproduction well.
 7893. The method of claim 7891, wherein varying theproduction location within the production well comprises varying alocation of perforations used to produce the mixture within theproduction well.
 7894. The method of claim 7890, wherein varying thelocation for producing the mixture comprises varying a productionlocation along a length of a production wellbore placed in theformation.
 7895. The method of claim 7890, wherein varying the locationfor producing the mixture comprises varying a location of a productionwell within the formation.
 7896. The method of claim 7890, whereinvarying the location for producing the mixture comprises varying anumber of production wells in the formation.
 7897. The method of claim7890, wherein varying the location for producing the mixture comprisesvarying a distance between a production well and one or more heaters.7898. The method of claim 7890, further comprising increasing thequality of the produced mixture by producing the mixture from an upperportion of the selected section.
 7899. The method of claim 7890, furthercomprising increasing a total mass recovery from the selected section byproducing the mixture from a lower portion of the selected section.7900. The method of claim 7890, further comprising selecting thelocation for production based on a price characteristic for producedhydrocarbons.
 7901. The method of claim 7900, wherein the pricecharacteristic is determined by multiplying a production rate of theproduced mixture at a selected API gravity from the selected section bya price obtainable for selling the produced mixture with the selectedAPI gravity.
 7902. The method of claim 7900, further comprisingadjusting the location for production based on a change in the pricecharacteristic.
 7903. The method of claim 7890, wherein the quality ofthe produced mixture comprises an API gravity of the produced mixture.7904. The method of claim 7890, wherein the produced mixture comprisesan acid number less than about
 1. 7905. The method of claim 7890,further comprising controlling the quality of the produced mixture bycontrolling the heat provided from at least one heater.
 7906. The methodof claim 7890, further comprising controlling the quality of theproduced mixture such that the produced mixture comprises a selectedminimum API gravity.
 7907. The method of claim 7890, further comprisingproducing the mixture when a partial pressure of hydrogen in theformation is at least about 0.5 bars absolute.
 7908. The method of claim7890, wherein the heat provided from at least one heater is transferredto at least a portion of the formation substantially by conduction.7909. The method of claim 7890, wherein one or more of the heaterscomprise heaters.
 7910. The method of claim 7890, wherein a ratio ofenergy output of the produced mixture to energy input into the formationis at least about
 5. 7911. A method for treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heaters to at least a portion of the relatively permeableformation; allowing the heat to transfer from the one or more heaters toa selected section of the formation such that the heat pyrolyzes atleast some hydrocarbons within the selected section; producing a firstmixture from a first portion of the selected section; and producing asecond mixture from a second portion of the selected section.
 7912. Themethod of claim 7911, further comprising producing a third mixture froma third portion of the selected section.
 7913. The method of claim 7911,further comprising producing a third mixture from a third portion of theselected section, wherein the first portion is substantially above thesecond portion, wherein the second portion is substantially above thethird portion, and wherein the first mixture is produced, then thesecond mixture, and then the third mixture.
 7914. The method of claim7911, wherein the first portion is substantially above the secondportion.
 7915. The method of claim 7911, wherein the first portion issubstantially below the second portion.
 7916. The method of claim 7911,wherein the first portion is substantially adjacent to the secondportion.
 7917. The method of claim 7911, wherein the first mixturecomprises an API gravity greater than about 20°.
 7918. The method ofclaim 7911, wherein the second mixture comprises an API gravity greaterthan about 20°.
 7919. The method of claim 7911, wherein the firstmixture comprises an acid number less than about
 1. 7920. The method ofclaim 7911, wherein the second mixture comprises an acid number lessthan about
 1. 7921. The method of claim 7911, wherein the first portioncomprises about an upper one-third of the formation.
 7922. The method ofclaim 7911, wherein the second portion comprises about a lower one-thirdof the formation.
 7923. The method of claim 7911, wherein the firstmixture is produced before the second mixture is produced.
 7924. Themethod of claim 7911, further comprising producing the first or thesecond mixture when a partial pressure of hydrogen in the formation isat least about 0.5 bars absolute.
 7925. The method of claim 7911,wherein the heat provided from at least one heater is transferred to atleast a portion of the formation substantially by conduction.
 7926. Themethod of claim 7911, wherein one or more of the heaters compriseheaters.
 7927. The method of claim 7911, wherein a ratio of energyoutput of the first or the second produced mixture to energy input intothe formation is at least about
 5. 7928. A method for treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heaters to a selected section of the formation suchthat the heat provided to the selected section pyrolyzes at least somehydrocarbons within a lower portion of the formation; and producing amixture from an upper portion of the formation, wherein the producedmixture comprises at least some pyrolyzed hydrocarbons from the lowerportion.
 7929. The method of claim 7928, wherein the produced mixturecomprises an API gravity greater than about 15°.
 7930. The method ofclaim 7928, wherein the produced mixture comprises an acid number lessthan about
 1. 7931. The method of claim 7928, wherein the upper portioncomprises about an upper one-half of the formation.
 7932. The method ofclaim 7928, wherein the lower portion comprises about a lower one-halfof the formation.
 7933. The method of claim 7928, further comprisingproducing the mixture of hydrocarbons as a vapor.
 7934. The method ofclaim 7928, further comprising providing heat from one or more heatersto a selected section of the formation such that the heat provided tothe selected section reduces the viscosity of at least some hydrocarbonswithin the selected section.
 7935. The method of claim 7928, furthercomprising inducing at least a portion of the hydrocarbons from thelower portion to flow into the upper portion.
 7936. The method of claim7928, wherein the upper portion and the lower portion are within theselected section.
 7937. The method of claim 7928, further comprisingproducing the mixture when a partial pressure of hydrogen in theformation is at least about 0.5 bars absolute.
 7938. The method of claim7928, wherein the heat provided from at least one heater is transferredto at least a portion of the formation substantially by conduction.7939. The method of claim 7928, wherein one or more of the heaterscomprise heaters.
 7940. The method of claim 7928, wherein a ratio ofenergy output of the produced mixture to energy input into the formationis at least about
 5. 7941. A method for treating a relatively permeableformation in situ, comprising: providing heat from one or more heatersto at least a portion of a relatively permeable formation; allowing heatto transfer from one or more heaters to a first selected section of arelatively permeable formation such that the heat reduces the viscosityof at least some hydrocarbons within the first selected section;producing a first mixture from the first selected section; allowing heatto transfer from one or more heaters to a second selected section of arelatively permeable formation such that the heat pyrolyzes at leastsome hydrocarbons within the second selected section; producing a secondmixture from the second selected section; and blending at least aportion of the first mixture with at least a portion of the secondmixture to produce a third mixture comprising a selected property. 7942.The method of claim 7941, wherein the selected property of the thirdmixture comprises an API gravity.
 7943. The method of claim 7941,wherein the selected property of the third mixture comprises an APIgravity of at least about 10°.
 7944. The method of claim 7941, whereinthe selected property of the third mixture comprises a selectedviscosity.
 7945. The method of claim 7941, wherein the selected propertyof the third mixture comprises a viscosity less than about 7500 cs.7946. The method of claim 7941, wherein the selected property of thethird mixture comprises a density.
 7947. The method of claim 7941,wherein the selected property of the third mixture comprises a densityless than about 1 g/cm³.
 7948. The method of claim 7941, wherein theselected property of the third mixture comprises an asphaltene tosaturated hydrocarbon ratio of less than about
 1. 7949. The method ofclaim 7941, wherein the selected property of the third mixture comprisesan aromatic hydrocarbon to saturated hydrocarbon ratio of less thanabout
 4. 7950. The method of claim 7941, wherein asphaltenes aresubstantially stable in the third mixture at ambient temperature. 7951.The method of claim 7941, wherein the third mixture is transportable.7952. The method of claim 7941, wherein the third mixture istransportable through a pipeline.
 7953. The method of claim 7941,wherein the first mixture comprises an API gravity less than about 15°.7954. The method of claim 7941, wherein the second mixture comprises anAPI gravity greater than about 25°.
 7955. The method of claim 7941,wherein the second mixture comprises an acid number less than about 1.7956. The method of claim 7941, further comprising selecting a ratio ofthe first mixture to the second mixture such that at least about 50% byweight of the initial mass of hydrocarbons in a selected portion of theformation is produced.
 7957. The method of claim 7941, wherein the thirdmixture comprises less than about 50% by weight of the second mixture.7958. The method of claim 7941, wherein the first selected sectioncomprises a depth of at least about 500 m below the surface of arelatively permeable formation.
 7959. The method of claim 7941, whereinthe second selected section comprises a depth less than about 500 mbelow the surface of a relatively permeable formation.
 7960. The methodof claim 7941, wherein the first selected section and the secondselected section are located in different relatively permeableformations.
 7961. The method of claim 7941, wherein the first selectedsection and the second selected section are located in differentrelatively permeable formations, and wherein the different relativelypermeable formation are vertically displaced.
 7962. The method of claim7941, wherein the first selected section and the second selected sectionare vertically displaced within a single relatively permeable formation.7963. The method of claim 7941, wherein the first selected section andthe second selected section are substantially adjacent within a singlerelatively permeable formation.
 7964. The method of claim 7941, whereinblending comprises injecting at least a portion of the second mixtureinto the first selected section such that the second mixture blends withat least a portion of the first mixture to produce the third mixture inthe first selected section.
 7965. The method of claim 7941, whereinblending comprises injecting at least a portion of the second mixtureinto a production well in the first selected section such that thesecond mixture blends with at least a portion of the first mixture toproduce the third mixture in the production well.
 7966. The method ofclaim 7941, further comprising producing a mixture when a partialpressure of hydrogen in the formation is at least about 0.5 barsabsolute.
 7967. The method of claim 7941, wherein the heat provided fromat least one heater is transferred to at least a portion of theformation substantially by conduction.
 7968. The method of claim 7941,wherein one or more of the heaters comprise heaters.
 7969. The method ofclaim 7941, wherein a ratio of energy output of the first or the secondproduced mixture to energy input into the formation is at least about 5.7970. A method for treating a relatively permeable formation in situ toproduce a blending agent, comprising: providing heat from one or moreheaters to at least a portion of the relatively permeable formation;allowing the heat to transfer from the one or more heaters to a selectedsection of the formation such that the heat pyrolyzes at least somehydrocarbons within the selected section; producing a blending agentfrom the selected section; and wherein at least a portion of theblending agent is adapted to blend with a liquid to produce a mixturewith a selected property.
 7971. The method of claim 7970, wherein theliquid comprises at least some heavy hydrocarbons.
 7972. The method ofclaim 7970, wherein the liquid comprises an API gravity below about 15°.7973. The method of claim 7970, wherein the liquid is viscous, andwherein a mixture produced by blending at least a portion of theblending agent with the liquid is less viscous than the liquid. 7974.The method of claim 7970, wherein the selected property of the mixturecomprises an API gravity.
 7975. The method of claim 7970, wherein theselected property of the mixture comprises an API gravity of at leastabout 10°.
 7976. The method of claim 7970, wherein the selected propertyof the mixture comprises a selected viscosity.
 7977. The method of claim7970, wherein the selected property of the mixture comprises a viscosityless than about 7500 cs.
 7978. The method of claim 7970, wherein theselected property of the mixture comprises a density.
 7979. The methodof claim 7970, wherein the selected property of the mixture comprises adensity less than about 1 g/cm³.
 7980. The method of claim 7970, whereinthe selected property of the mixture comprises an asphaltene tosaturated hydrocarbon ratio of less than about
 1. 7981. The method ofclaim 7970, wherein the selected property of the mixture comprises anaromatic hydrocarbon to saturated hydrocarbon ratio of less than about4.
 7982. The method of claim 7970, wherein asphaltenes are substantiallystable in the mixture at ambient temperature.
 7983. The method of claim7970, wherein the mixture is transportable.
 7984. The method of claim7970, wherein the mixture is transportable through a pipeline.
 7985. Themethod of claim 7970, wherein the liquid has a viscosity sufficientlyhigh to inhibit economical transport of the liquid over 100 km via apipeline but the mixture has a reduced viscosity that allows economicaltransport of the mixture over 100 km via a pipeline.
 7986. The method ofclaim 7970, further comprising producing the liquid from a secondsection of a relatively permeable formation and blending the liquid withthe blending agent to produce the mixture.
 7987. The method of claim7970, further comprising producing the liquid from a second section of arelatively permeable formation and blending the liquid with the blendingagent to produce the mixture, wherein the mixture comprises less thanabout 50% by weight of the blending agent.
 7988. The method of claim7970, further comprising injecting the blending agent into a secondsection of a relatively permeable formation such that the blending agentblends with the liquid in the second section to produce the mixture.7989. The method of claim 7970, further comprising injecting theblending agent into a production well in a second section of arelatively permeable formation such that the blending agent blends withthe liquid in the production well to produce the mixture.
 7990. Themethod of claim 7970, further comprising producing the blending agentwhen a partial pressure of hydrogen in the formation is at least about0.5 bars absolute.
 7991. The method of claim 7970, wherein the heatprovided from at least one heater is transferred to at least a portionof the formation substantially by conduction.
 7992. The method of claim7970, wherein one or more of the heaters comprise heaters.
 7993. Themethod of claim 7970, wherein a ratio of energy output of the blendingagent to energy input into the formation is at least about
 5. 7994. Themethod of claim 7970, wherein the blending agent comprises an acidnumber less than about
 1. 7995. A blending agent produced by a method,comprising: providing heat from one or more heaters to at least aportion of a relatively permeable formation; allowing the heat totransfer from the one or more heaters to a selected section of theformation such that the heat pyrolyzes at least some hydrocarbons withinthe selected section; and producing the blending agent from the selectedsection; wherein at least a portion of the blending agent is adapted toblend with a liquid to produce a mixture with a selected property. 7996.The blending agent of claim 7995, wherein the blending agent comprisesan API gravity of at least about 20°.
 7997. The blending agent of claim7995, wherein the blending agent comprises an acid number less thanabout
 1. 7998. The blending agent of claim 7995, wherein the blendingagent comprises an asphaltene weight percentage less than about 0.5%.7999. The blending agent of claim 7995, wherein the blending agentcomprises a combined nitrogen, oxygen, and sulfur weight percentage lessthan about 5%.
 8000. The blending agent of claim 7995, whereinasphaltenes are substantially stable in the mixture at ambienttemperature.
 8001. The blending agent of claim 7995, wherein the methodfurther comprises producing the blending agent when a partial pressureof hydrogen in the formation is at least about 0.5 bars absolute. 8002.The blending agent of claim 7995, wherein the method further comprisesthe heat provided from at least one heater transferring to at least aportion of the formation substantially by conduction.
 8003. The blendingagent of claim 7995, wherein the method further comprises one or more ofthe heaters comprising heaters.
 8004. The blending agent of claim 7995,wherein the method further comprises a ratio of energy output of theblending agent to energy input into the formation being at least about5.
 8005. A method for treating a relatively permeable formation in situ,comprising: producing a first mixture from a first selected section of arelatively permeable formation, wherein the first mixture comprisesheavy hydrocarbons; providing heat from one or more heaters to a secondselected section of the relatively permeable formation such that theheat pyrolyzes at least some hydrocarbons within the second selectedsection; producing a second mixture from the second selected section;and blending at least a portion of the first mixture with at least aportion of the second mixture to produce a third mixture comprising aselected property.
 8006. The method of claim 8005, further comprisingcold producing the first mixture from the first selected section. 8007.The method of claim 8005, wherein producing the first mixture from thefirst selected section comprises producing the first mixture through aproduction well in or proximate the formation.
 8008. The method of claim8005, wherein the selected property of the third mixture comprises anAPI gravity.
 8009. The method of claim 8005, wherein the selectedproperty of the third mixture comprises a selected viscosity.
 8010. Themethod of claim 8005, wherein the selected property of the third mixturecomprises a density.
 8011. The method of claim 8005, wherein theselected property of the third mixture comprises an asphaltene tosaturated hydrocarbon ratio of less than about
 1. 8012. The method ofclaim 8005, wherein the selected property of the third mixture comprisesan aromatic hydrocarbon to saturated hydrocarbon ratio of less thanabout
 4. 8013. The method of claim 8005, wherein asphaltenes aresubstantially stable in the third mixture at ambient temperature. 8014.The method of claim 8005, wherein the third mixture is transportable.8015. The method of claim 8005, wherein the third mixture istransportable through a pipeline.
 8016. The method of claim 8005,wherein the liquid has a viscosity sufficiently high to inhibiteconomical transport of the liquid over 100 km via a pipeline but themixture has a reduced viscosity that allows economical transport of themixture over 100 km via a pipeline.
 8017. The method of claim 8005,wherein the first mixture comprises an API gravity less than about 15°.8018. The method of claim 8005, wherein the second mixture comprises anAPI gravity greater than about 25°.
 8019. The method of claim 8005,wherein the second mixture comprises an acid number less than about 1.8020. The method of claim 8005, wherein the third mixture comprises lessthan about 50% by weight of the second mixture.
 8021. The method ofclaim 8005, wherein the first selected section comprises a depth of atleast about 500 m below the surface of a relatively permeable formation.8022. The method of claim 8005, wherein the second selected sectioncomprises a depth less than about 500 m below the surface of arelatively permeable formation.
 8023. The method of claim 8005, furthercomprising producing a mixture when a partial pressure of hydrogen inthe formation is at least about 0.5 bars absolute.
 8024. The method ofclaim 8005, wherein the heat provided from at least one heater istransferred to at least a portion of the formation substantially byconduction.
 8025. The method of claim 8005, wherein one or more of theheaters comprise heaters.
 8026. The method of claim 8005, wherein aratio of energy output of the second mixture to energy input into theformation is at least about
 5. 8027. A method for treating a relativelypermeable formation in situ, comprising: providing heat from one or moreheaters to a selected section of a relatively permeable formation suchthat the heat pyrolyzes at least some hydrocarbons within the selectedsection; producing a blending agent from the selected section; andinjecting at least a portion of the blending agent into a second sectionof a relatively permeable formation to produce a mixture having aselected property, wherein the second section comprises at least someheavy hydrocarbons.
 8028. The method of claim 8027, wherein the selectedproperty of the mixture comprises an API gravity.
 8029. The method ofclaim 8027, wherein the selected property of the mixture comprises anAPI gravity of at least about 10°.
 8030. The method of claim 8027,wherein the selected property of the mixture comprises a selectedviscosity.
 8031. The method of claim 8027, wherein the selected propertyof the mixture comprises a viscosity less than about 7500 cs.
 8032. Themethod of claim 8027, wherein the selected property of the mixturecomprises a density.
 8033. The method of claim 8027, wherein theselected property of the mixture comprises a density less than about 1g/cm³.
 8034. The method of claim 8027, wherein the selected property ofthe mixture comprises an asphaltene to saturated hydrocarbon ratio ofless than about
 1. 8035. The method of claim 8027, wherein the selectedproperty of the mixture comprises an aromatic hydrocarbon to saturatedhydrocarbon ratio of less than about
 4. 8036. The method of claim 8027,wherein asphaltenes are substantially stable in the mixture at ambienttemperature.
 8037. The method of claim 8027, wherein the mixture istransportable.
 8038. The method of claim 8027, wherein the mixture istransportable through a pipeline.
 8039. The method of claim 8027,wherein second section comprises heavy hydrocarbons having an APIgravity less than about 15°.
 8040. The method of claim 8027, wherein theblending agent comprises an API gravity greater than about 25°. 8041.The method of claim 8027, wherein the blending agent comprises an acidnumber less than about
 1. 8042. The method of claim 8027, wherein themixture comprises less than about 50% by weight of the blending agent.8043. The method of claim 8027, wherein the selected section comprises adepth of at least about 500 m below the surface of a relativelypermeable formation.
 8044. The method of claim 8027, wherein the secondsection comprises a depth less than about 500 m below the surface of arelatively permeable formation.
 8045. The method of claim 8027, whereinthe selected section and the second section are located in differentrelatively permeable formations.
 8046. The method of claim 8027, whereinthe selected section and the second section are located in differentrelatively permeable formations, and wherein the different relativelypermeable formation are vertically displaced.
 8047. The method of claim8027, wherein the selected section and the second section are verticallydisplaced within a single relatively permeable formation.
 8048. Themethod of claim 8027, wherein the selected section and the secondsection are substantially adjacent within a single relatively permeableformation.
 8049. The method of claim 8027, wherein the blending agent isinjected into a production well in the second section, and wherein themixture is produced in the production well.
 8050. The method of claim8027, further comprising producing the mixture from the second section.8051. The method of claim 8027, further comprising producing theblending agent when a partial pressure of hydrogen in the formation isat least about 0.5 bars absolute.
 8052. The method of claim 8027,wherein the heat provided from at least one heater is transferred to atleast a portion of the formation substantially by conduction.
 8053. Themethod of claim 8027, wherein one or more of the heaters compriseheaters.
 8054. The method of claim 8027, wherein a ratio of energyoutput of the produced mixture to energy input into the formation is atleast about
 5. 8055. A method for treating a relatively permeableformation in situ, comprising: providing heat from one or more heatersto at least a portion of the relatively permeable formation; allowingthe heat to transfer from the one or more heaters to a selected sectionof the formation such that the heat reduces the viscosity of at leastsome hydrocarbons within the selected section; producing the mixturefrom the selected section; and adjusting a parameter for producing thedesired mixture based on at least one price characteristic of thedesired mixture.
 8056. The method of claim 8055, further comprisingallowing the heat to transfer from the one or more heaters to a selectedsection of the formation such that the heat pyrolyzes at least somehydrocarbons within the selected section.
 8057. The method of claim8055, wherein adjusting the parameter comprises selecting a location inthe selected section for production of the mixture based on at least oneprice characteristic of the mixture.
 8058. The method of claim 8055,wherein adjusting the parameter comprises selecting a productionlocation in the selected section to produce a selected API gravity inthe produced mixture.
 8059. The method of claim 8055, wherein at leastone price characteristic is determined by multiplying a production rateof the produced mixture at a selected API gravity from the selectedsection by a price obtainable for selling the produced mixture with theselected API gravity.
 8060. The method of claim 8055, wherein adjustingthe parameter comprises controlling at least one operating condition inthe selected section.
 8061. The method of claim 8060, whereincontrolling at least one operating condition comprises controlling heatoutput from at least one of the heaters.
 8062. The method of claim 8061,wherein controlling the heat output from at least one of the heaterscontrols a heating rate in the selected section.
 8063. The method ofclaim 8060, wherein controlling at least one operating conditioncomprises controlling a pressure in the selected section.
 8064. Themethod of claim 8055, wherein at least one price characteristiccomprises a characteristic based on a selling price for sulfur producedfrom the formation.
 8065. The method of claim 8055, wherein at least oneprice characteristic comprises a characteristic based on a selling pricefor metal produced from the formation.
 8066. The method of claim 8055,wherein at least one price characteristic comprises a characteristicbased on a ratio of paraffins to aromatics in the mixture.
 8067. Themethod of claim 8055, further comprising producing the mixture when apartial pressure of hydrogen in the formation is at least about 0.5 barsabsolute.
 8068. The method of claim 8055, wherein the heat provided fromat least one heater is transferred to at least a portion of theformation substantially by conduction.
 8069. The method of claim 8055,wherein one or more of the heaters comprise heaters.
 8070. The method ofclaim 8055, wherein a ratio of energy output of the produced mixture toenergy input into the formation is at least about
 5. 8071. The method ofclaim 8055, wherein the produced mixture comprises an acid number lessthan about
 1. 8072. A method for forming at least one opening in ageological formation, comprising: forming a portion of an opening in theformation; providing an acoustic wave to at least a portion of theformation, wherein the acoustic wave is configured to propagate betweenat least one geological discontinuity of the formation and at least aportion of the opening; sensing at least one reflection of the acousticwave in at least a portion of the opening; using the sensed reflectionto assess an approximate location of at least a portion of the openingin the formation; and forming an additional portion of the opening basedon, at least in part, the assessed approximate location of at least aportion of the opening.
 8073. The method of claim 8072, furthercomprising using the sensed reflection to maintain an approximatedesired location of the opening between an overburden of the formationand an underburden of the formation.
 8074. The method of claim 8072,wherein at least one geological discontinuity comprises a boundary ofthe formation.
 8075. The method of claim 8072, further comprising usingthe sensed reflection to maintain the location of the opening atapproximately midway between an overburden of the formation and anunderburden of the formation.
 8076. The method of claim 8072, furthercomprising producing the acoustic wave using a monopole or dipolesource.
 8077. The method of claim 8072, further comprising sensing thereflection of the acoustic wave using one or more sensors in at least aportion of the opening.
 8078. The method of claim 8072, furthercomprising producing the acoustic wave using a source for producing theacoustic wave in at least a portion of the opening.
 8079. The method ofclaim 8072, further comprising producing the acoustic wave using asource for producing the acoustic wave in at least a portion of theopening, and sensing the acoustic wave using one or more sensors in atleast a portion of the opening.
 8080. The method of claim 8072, furthercomprising sensing the reflection of the acoustic wave during formationof at least a portion of the opening in the formation.
 8081. The methodof claim 8072, further comprising using a calculated or assessedacoustic velocity in the formation when using the sensed reflection toassess the location of the opening in the formation.
 8082. The method ofclaim 8072, further comprising propagating an acoustic wave between anoverburden of the formation and the opening.
 8083. The method of claim8072, further comprising propagating an acoustic wave between anunderburden of the formation and the opening.
 8084. The method of claim8072, further comprising propagating an acoustic wave between anoverburden of the formation and the opening, and an underburden of theformation and the opening.
 8085. The method of claim 8072, furthercomprising using information from the sensed acoustic wave to, at leastin part, guide a drilling system in forming the opening.
 8086. Themethod of claim 8072, further comprising substantially simultaneouslyproviding acoustic waves, sensing reflected acoustic waves, and usinginformation from the sensed acoustic waves to, at least in part, guide adrilling system in forming the opening.
 8087. The method of claim 8072,further comprising using information from the sensed acoustic wave to,at least in part, substantially simultaneously guide a drilling systemin forming the opening.
 8088. The method of claim 8072, furthercomprising using information from the sensed acoustic wave to assess alocation of at least a part of the opening, and then using such assessedlocation to, at least in part, guide a drilling system in forming theopening.
 8089. The method of claim 8072, further comprising usinginformation from the sensed acoustic waves to assess locations of partsof the opening, and then using such assessed locations to, at least inpart, guide a drilling system in forming the opening.
 8090. The methodof claim 8072, wherein a first opening is formed using the sensedacoustic wave, and further comprising forming one or more additionalopenings by using magnetic tracking to form one or more additionalopenings at a selected approximate distance from the first opening.8091. The method of claim 8072, further comprising assessing anapproximate orientation of the opening with an inclinometer.
 8092. Themethod of claim 8072, further comprising assessing an approximatelocation of the opening relative to a second opening in the formation bydetecting one or more magnetic fields produced from the second opening.8093. The method of claim 8072, further comprising assessing anapproximate location of the opening relative to a second opening in theformation by detecting one or more magnetic fields produced from thesecond opening with a magnetometer.
 8094. The method of claim 8072,further comprising assessing an approximate location of the openingrelative to a second opening in the formation by detecting one or moremagnetic fields produced from the second opening so that the opening isformed at an approximate desired distance from the second opening. 8095.The method of claim 8072, wherein the formation comprising hydrocarbons,and further comprising heating at least a portion of the formation, andpyrolyzing at least some hydrocarbons in the formation.
 8096. The methodof claim 8072, further comprising heating at least a portion of theformation, and controlling a pressure and a temperature within at leasta part of the formation, wherein the pressure is controlled as afunction of temperature, and/or the temperature is controlled as afunction of pressure.
 8097. The method of claim 8072, further comprisingheating at least a portion of the formation, and producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 8098. Themethod of claim 8072, further comprising heating at least a portion ofthe formation, controlling a pressure within at least a part of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 8099. The method of claim 8072, further comprising heating atleast a portion of the formation, and controlling formation conditionssuch that a produced mixture comprises a partial pressure of H₂ withinthe mixture greater than about 0.5 bars.
 8100. The method of claim 8072,further comprising heating at least a portion of the formation, andaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 8101. The method of claim 8072, further comprising heating at leasta portion of the formation to a minimum pyrolysis temperature of about270° C.
 8102. A method for heating a hydrocarbon containing formation,comprising: providing heat to the formation from one or more heaters inone or more openings in the formation, wherein at least one of theopenings has been formed by: forming a portion of an opening in theformation; providing an acoustic wave to at least a portion of theformation, wherein the acoustic wave is configured to propagate betweenat least one geological discontinuity of the formation and at least aportion of the opening; sensing at least one reflection of the acousticwave in at least a portion of the opening; and using the sensedreflection to assess an approximate location of at least a portion ofthe opening in the formation.
 8103. The method of claim 8102, wherein atleast one portion of an opening has been formed based on, at least inpart, the assessed approximate location of at least a portion of theopening.
 8104. The method of claim 8102, wherein at least one portion ofan opening has been formed using the sensed reflection to maintain anapproximate desired location of the opening between an overburden of theformation and an underburden of the formation.
 8105. The method of claim8102, wherein at least one geological discontinuity comprises a boundaryof the formation.
 8106. The method of claim 8102, wherein at least oneportion of an opening has been formed based on, at least in part, usingthe sensed reflection to maintain the location of the opening atapproximately midway between an overburden of the formation and anunderburden of the formation.
 8107. The method of claim 8102, wherein atleast one portion of an opening has been formed based on, at least inpart, producing the acoustic wave using a monopole or dipole source.8108. The method of claim 8102, wherein at least one portion of anopening has been formed based on, at least in part, sensing thereflection of the acoustic wave using one or more sensors in at least aportion of the opening.
 8109. The method of claim 8102, wherein at leastone portion of an opening has been formed based on, at least in part,producing the acoustic wave using a source for producing the acousticwave in at least a portion of the opening.
 8110. The method of claim8102, wherein at least one portion of an opening has been formed basedon, at least in part, producing the acoustic wave using a source forproducing the acoustic wave in at least a portion of the opening, andsensing the acoustic wave using one or more sensors in at least aportion of the opening.
 8111. The method of claim 8102, wherein at leastone portion of an opening has been formed based on, at least in part,sensing the reflection of the acoustic wave during formation of at leasta portion of the opening in the formation.
 8112. The method of claim8102, wherein at least one portion of an opening has been formed basedon, at least in part, using a calculated or assessed velocity in theformation when using the sensed reflection to assess the location of theopening in the formation.
 8113. The method of claim 8102, wherein atleast one portion of an opening has been formed based on, at least inpart, propagating an acoustic wave between an overburden of theformation and the opening.
 8114. The method of claim 8102, wherein atleast one portion of an opening has been formed based on, at least inpart, propagating an acoustic wave between an underburden of theformation and the opening.
 8115. The method of claim 8102, wherein atleast one portion of an opening has been formed based on, at least inpart, propagating an acoustic wave between an overburden of theformation and the opening, and an underburden of the formation and theopening.
 8116. The method of claim 8102, wherein at least one portion ofan opening has been formed based on, at least in part, using informationfrom the sensed acoustic wave to, at least in part, guide a drillingsystem in forming the opening.
 8117. The method of claim 8102, whereinat least one portion of an opening has been formed based on, at least inpart, substantially simultaneously providing acoustic waves, sensingreflected acoustic waves, and using information from the sensed acousticwaves to, at least in part, guide a drilling system in forming theopening.
 8118. The method of claim 8102, wherein at least one portion ofan opening has been formed based on, at least in part, using informationfrom the sensed acoustic wave to, at least in part, substantiallysimultaneously guide a drilling system in forming the opening.
 8119. Themethod of claim 8102, wherein at least one portion of an opening hasbeen formed based on, at least in part, using information from thesensed acoustic wave to assess a location of at least a part of theopening, and then using such assessed location to, at least in part,guide a drilling system in forming the opening.
 8120. The method ofclaim 8102, wherein at least one portion of an opening has been formedbased on, at least in part, using information from the sensed acousticwaves to assess locations of parts of the opening, and then using suchassessed locations to, at least in part, guide a drilling system informing the opening.
 8121. The method of claim 8102, wherein at leastone portion of an opening has been formed based on, at least in part,using the sensed acoustic wave, and further comprising forming one ormore additional openings by using magnetic tracking to form one or moreadditional openings at a selected approximate distance from the firstopening.
 8122. The method of claim 8102, further comprising assessing anapproximate orientation of the opening with an inclinometer.
 8123. Themethod of claim 8102, further comprising assessing an approximatelocation of the opening relative to a second opening in the formation bydetecting one or more magnetic fields produced from the second opening.8124. The method of claim 8102, further comprising assessing anapproximate location of the opening relative to a second opening in theformation by detecting one or more magnetic fields produced from thesecond opening with a magnetometer.
 8125. The method of claim 8102,further comprising assessing an approximate location of the openingrelative to a second opening in the formation by detecting one or moremagnetic fields produced from the second opening so that the opening isformed at an approximate desired distance from the second opening. 8126.The method of claim 8102, further comprising pyrolyzing at least somehydrocarbons in the formation.
 8127. The method of claim 8102, furthercomprising controlling a pressure and a temperature within at least apart of the formation, wherein the pressure is controlled as a functionof temperature, and/or the temperature is controlled as a function ofpressure.
 8128. The method of claim 8102, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.8129. The method of claim 8102, further comprising controlling apressure within at least a part of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 8130. The method of claim8102, further comprising controlling formation conditions such that aproduced mixture comprises a partial pressure of H₂ within the mixturegreater than about 0.5 bars.
 8131. The method of claim 8102, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 8132. The method of claim 8102, furthercomprising heating at least a portion of the formation to a minimumpyrolysis temperature of about 270° C.
 8133. A method for forming one ormore openings in a hydrocarbon containing formation, comprising: forminga first opening in the formation; providing a plurality of magnets tothe first opening, wherein the plurality of magnets is positioned alongat least a portion of the first opening, and wherein the plurality ofmagnets produces a series of magnetic fields along at least the portionof the first opening; and forming a second opening in the formationusing one or more of the series of magnetic fields such that the secondopening is spaced at an approximate desired distance from the firstopening.
 8134. The method of claim 8133, wherein the plurality ofmagnets comprises a magnetic string.
 8135. The method of claim 8133,further comprising using magnetic tracking of one or more of the seriesof magnetic fields to space the second opening at an approximate desireddistance from the first opening.
 8136. The method of claim 8133, furthercomprising using a magnetometer in the second opening, and one or moreof the magnetic fields, to space the second opening at an approximatedesired distance from the first opening.
 8137. The method of claim 8133,further comprising using a magnetometer and an inclinometer in thesecond opening, and one or more of the magnetic fields, to space thesecond opening at an approximate desired distance from the firstopening.
 8138. The method of claim 8133, wherein the plurality ofmagnets comprises magnets, and wherein the magnets comprise aluminum,cobalt, and nickel.
 8139. The method of claim 8133, wherein theplurality of magnets is positioned in a casing.
 8140. The method ofclaim 8133, wherein the plurality of magnets is positioned in aferromagnetic casing.
 8141. The method of claim 8133, wherein theplurality of magnets is positioned in a heater casing.
 8142. The methodof claim 8133, wherein the plurality of magnets is positioned in aperforated casing.
 8143. The method of claim 8133, wherein at least aportion of the plurality of magnets is placed in a conduit.
 8144. Themethod of claim 8133, wherein the plurality of magnets comprises atleast two junctions of opposing poles of opposite polarity separated bya selected distance.
 8145. The method of claim 8133, wherein theplurality of magnets comprises at least two junctions of opposing polesof opposite polarity separated by a selected distance, and wherein theselected distance is substantially similar to the desired distancebetween the first opening and the second opening.
 8146. The method ofclaim 8133, wherein the plurality of magnets comprises at least twojunctions of opposing poles of opposite polarity separated by a selecteddistance, and wherein the selected distance is greater than about 1 mand less than about 500 m.
 8147. The method of claim 8133, wherein theplurality of magnets comprises at least two magnetic segments that arepositioned such that opposing poles from each magnetic segment aresubstantially adjacent to one another, thereby forming a junction ofopposing poles.
 8148. The method of claim 8133, further comprisingmoving the plurality of magnets in the first opening to vary at leastone magnetic field with time.
 8149. The method of claim 8133, furthercomprising moving the plurality of magnets in the first opening toincrease a length of the second opening.
 8150. The method of claim 8133,further comprising forming a plurality of openings proximate to thefirst opening.
 8151. The method of claim 8133, wherein the first openingis a substantially vertical opening, and wherein the second opening is asubstantially horizontal opening that passes the first opening at aselected distance from the first opening and at a selected depth in theformation.
 8152. The method of claim 8133, wherein the first openingcomprises a non-ferromagnetic casing.
 8153. The method of claim 8133,wherein the series of the magnetic fields comprises a first magneticfield and a second magnetic field and wherein a strength of the firstmagnetic field differs from a strength of the second magnetic field.8154. The method of claim 8133, wherein the series of the magneticfields comprises a first magnetic field and a second magnetic field andwherein a strength of the first magnetic field is about the same as astrength of the second magnetic field.
 8155. The method of claim 8133,wherein the series of the magnetic fields comprises a pole strengthbetween about 100 Gauss and about 2000 Gauss.
 8156. The method of claim8133, wherein the first opening comprises a center opening in a patternof openings, the method further comprising forming a plurality ofopenings in the pattern of openings proximate to the first opening.8157. The method of claim 8133, wherein the first opening comprises acenter opening in a pattern of openings, the method further comprisingforming a plurality of openings in the pattern of openings proximate tothe first opening, and wherein each of the plurality of openings isspaced at an approximate desired distance from the first opening. 8158.The method of claim 8133, further comprising providing at least oneheating mechanism in the first opening and at least one heatingmechanism in the second opening such that the heating mechanisms can beused to provide heat to at least a portion of the formation.
 8159. Themethod of claim 8133, wherein a deviation in the spacing between thesecond opening and the first opening is less than or equal to about ±1m.
 8160. The method of claim 8133, wherein a deviation in the spacingbetween the second opening and the first opening is less than or equalto about ±0.5 m.
 8161. The method of claim 8133, further comprisingmeasuring a magnetic field when the plurality of magnets is at a firstposition, moving the plurality of magnets, measuring a magnetic fieldwhen the plurality of magnets is at a second position, and whereinmeasurements at the two positions are used to calibrate for an effect ofother magnetic fields.
 8162. The method of claim 8161, wherein at leasttwo positions comprise positions spaced apart by multiples of L/4, andwherein L is a distance between two junctions of opposing poles in theplurality of magnets.
 8163. The method of claim 8133, wherein ameasurement of the series of magnetic fields is taken at two positionsseparated by L/2 of the plurality of magnets in the first opening toreduce an effect of fixed magnetic fields on a determination of distancebetween the first opening and the second opening, and wherein L is adistance between two junctions of opposing poles in the plurality ofmagnets.
 8164. The method of claim 8133, wherein the plurality ofmagnets are positioned in a linear array.
 8165. The method of claim8133, wherein the plurality of magnets is configured so that theplurality of magnets produces a magnetic field when an electric currentis applied to the magnets.
 8166. The method of claim 8133, wherein atleast one heater is placed in at least one opening in the formation, andwherein the heater can be used in a method comprising: providing heatfrom the at least one heater to a portion of the formation; pyrolyzingat least some hydrocarbons in the formation; and producing a mixturefrom the formation, wherein the mixture comprises at least somepyrolyzed hydrocarbons.
 8167. A method for forming one or more openingsin a hydrocarbon containing formation, comprising: forming a firstopening in the formation; providing a magnetic string to the firstopening, wherein the magnetic string is positioned along at least aportion of the first opening, wherein the magnetic string produces twoor more magnetic fields, wherein the magnetic string comprises two ormore magnetic segments, and wherein at least two magnetic segments arepositioned such that opposing poles from each magnetic segment aresubstantially adjacent to each other, thereby forming a junction ofopposing poles; and forming a second opening in the formation using oneor more of the magnetic fields such that the second opening is spaced atan approximate desired distance from the first opening.
 8168. The methodof claim 8167, wherein at least one magnetic segment comprises aplurality of magnets.
 8169. The method of claim 8167, further comprisingusing magnetic tracking of one or more of the series of magnetic fieldsto space the second opening at an approximate desired distance from thefirst opening.
 8170. The method of claim 8167, further comprising usinga magnetometer in the second opening, and one or more of the magneticfields, to space the second opening at an approximate desired distancefrom the first opening.
 8171. The method of claim 8167, furthercomprising using a magnetometer and an inclinometer in the secondopening, and one or more of the magnetic fields, to space the secondopening at an approximate desired distance from the first opening. 8172.The method of claim 8167, wherein at least one magnetic segmentcomprises a plurality of Alnico magnets.
 8173. The method of claim 8167,wherein at least one magnetic segment comprises a plurality of magnets,and wherein the at least one magnetic segment has one effective northpole and one effective south pole.
 8174. The method of claim 8167,wherein a distance between two junctions of opposing poles with oppositepolarity is substantially similar to the desired distance between thefirst opening and the second opening.
 8175. The method of claim 8167,wherein a distance between two junctions of opposing poles with oppositepolarity is greater than about 1 m and less than about 500 m.
 8176. Themethod of claim 8167, further comprising moving the magnetic string inthe first opening.
 8177. The method of claim 8167, further comprisingmoving the magnetic string in the first opening such that at least oneof the magnetic fields varies with time.
 8178. The method of claim 8167,further comprising moving the magnetic string in the first opening toincrease a length of the second opening.
 8179. The method of claim 8167,further comprising forming a plurality of openings proximate to thefirst opening.
 8180. The method of claim 8167, wherein the first openingis a substantially vertical opening, and wherein the second opening is asubstantially horizontal opening that passes the first opening at aselected distance from the first opening and at a selected depth in theformation.
 8181. The method of claim 8167, wherein the first openingcomprises a non-ferromagnetic casing.
 8182. The method of claim 8167,wherein the magnetic fields comprise a series of magnetic fields, andwherein a strength of a first magnetic field differs from a strength ofa second magnetic field.
 8183. The method of claim 8167, wherein themagnetic fields comprise a series of magnetic fields, and wherein astrength of a first magnetic field is about the same as a strength of asecond magnetic field.
 8184. The method of claim 8167, wherein the firstopening comprises a center opening in a pattern of openings, the methodfurther comprising forming a plurality of openings in the pattern ofopenings proximate to the first opening.
 8185. The method of claim 8167,wherein the first opening comprises a center opening in a pattern ofopenings, the method further comprising forming a plurality of openingsin the pattern of openings proximate to the first opening, and whereineach of the plurality of openings is spaced at an approximate desireddistance from the first opening.
 8186. The method of claim 8167, furthercomprising providing at least one heating mechanism in the first openingand at least one heating mechanism in the second opening such that theheating mechanisms can be used to provide heat to at least a portion ofthe formation.
 8187. The method of claim 8167, wherein the magneticstring is positioned in a conduit.
 8188. The method of claim 8167,wherein the magnetic string is positioned in a conduit, and wherein theconduit comprises non-magnetic material.
 8189. The method of claim 8167,wherein at least two magnetic segments comprising the junction ofopposing poles are positioned in a section of conduit, wherein thesection of conduit is coupled to at least one other section of conduit,and at least one other section of conduct comprises at least twomagnetic segments comprising opposing poles to produce a junction ofopposing poles, and wherein the junction of opposing poles of at leastone other section of conduit comprises an opposite polarity of thejunction of opposing poles of the section of conduit.
 8190. The methodof claim 8167, wherein the magnetic string is positioned in a casing.8191. The method of claim 8167, wherein the magnetic string ispositioned in a heater casing.
 8192. The method of claim 8167, whereinthe magnetic string is positioned in a ferromagnetic casing.
 8193. Themethod of claim 8167, wherein the magnetic string is positioned in alinear array.
 8194. The method of claim 8167, wherein a deviation in thespacing between the second opening and the first opening is less than orequal to about ±1 m.
 8195. The method of claim 8167, wherein a deviationin the spacing between the second opening and the first opening is lessthan or equal to about ±0.5 m.
 8196. The method of claim 8167, furthercomprising measuring a magnetic field when the magnetic string is at afirst position, moving the magnetic string, measuring a magnetic fieldwhen the magnetic string is at a second position, and whereinmeasurements at the two positions are used to calibrate for an effect ofother magnetic fields.
 8197. The method of claim 8196, wherein the atleast two positions comprise positions spaced apart by multiples of L/4,and wherein L is a distance between two junctions of opposing poles inthe magnetic string.
 8198. The method of claim 8167, wherein ameasurement of the series of magnetic fields is taken at two positionsseparated by L/2 of the magnetic string in the first opening to reducean effect of fixed magnetic fields on a determination of distancebetween the first opening and the second opening, and wherein L is adistance between two junctions of opposing poles in the magnetic string.8199. The method of claim 8167, wherein the magnetic string isconfigured so that the magnetic string produces a magnetic field when anelectric current is applied to the magnetic string.
 8200. The method ofclaim 8167, wherein at least one heater is placed in at least oneopening in the formation, and wherein the heater can be used in a methodcomprising: providing heat from the at least one heater to a portion ofthe formation; pyrolyzing at least some hydrocarbons in the formation;and producing a mixture from the formation, wherein the mixturecomprises at least some pyrolyzed hydrocarbons.
 8201. A system fordrilling openings in a hydrocarbon containing formation, comprising: adrilling apparatus; a magnetic string comprising two or more magneticsegments positionable in a conduit, wherein each of the magneticsegments comprises a plurality of magnets; and a sensor configurable todetect a magnetic field in the formation.
 8202. The system of claim8201, wherein the sensor is coupled to the drilling apparatus.
 8203. Thesystem of claim 8201, wherein the magnetic string further comprises oneor more fasteners configurable to inhibit movement of the magneticsegments relative to the conduit.
 8204. The system of claim 8201,wherein one or more magnetic segments are positioned such that opposingpoles from each magnetic segment are substantially adjacent to each,thereby forming a junction of opposing poles.
 8205. The system of claim8201, wherein the magnetic string is positioned in a first opening inthe formation and the drilling apparatus is positioned in a secondopening in the formation, and wherein a distance between two junctionsof opposing poles with opposite polarity in the magnetic string issubstantially similar to the desired distance between the first openingand the second opening.
 8206. The system of claim 8201, wherein themagnetic string is positionable in at least a portion of an opening inthe formation.
 8207. The system of claim 8201, wherein the magneticstring is positionable in at least a portion of an opening in theformation and wherein the magnetic string produces a magnetic field in aportion of the formation.
 8208. The system of claim 8201, wherein themagnetic string produces a series of magnetic fields along at least aportion of an opening in the formation.
 8209. The system of claim 8201,wherein the magnetic string is movable in an opening in the formation.8210. The system of claim 8201, wherein the magnetic string ispositioned in a first opening in the formation and the drillingapparatus is positioned in a second opening in the formation, andwherein a position of the magnetic string in the first opening can beadjusted to increase a length of the second opening.
 8211. The system ofclaim 8201, wherein the conduit comprises non-ferromagnetic material.8212. The system of claim 8201, wherein the magnetic string ispositioned in an opening in the formation, and wherein the openingcomprises a casing.
 8213. The system of claim 8201, wherein the conduitcomprises one or more sections, and wherein each section comprises twomagnetic segments.
 8214. The system of claim 8201, wherein the conduitcomprises one or more sections, and wherein each section comprises twomagnetic segments positioned such that the two magnetic segments form ajunction of opposing poles approximately at the center of each section.8215. The system of claim 8201, further comprising a magnetometercoupled to the drilling apparatus, the magnetometer being configured tosense a magnetic field formed by at least one of the magnetic segments.8216. The system of claim 8201, further comprising a magnetometer and aninclinometer coupled to the drilling apparatus, the magnetometer beingconfigured to sense a magnetic field formed by at least one of themagnetic segments.
 8217. The system of claim 8201, further comprising amagnetometer coupled to the drilling apparatus, the magnetometer beingconfigured to sense a magnetic field formed by at least one of themagnetic segments, wherein the system is configured to control thedrilling apparatus based on, at least in part, sensed readings from themagnetometer.
 8218. The system of claim 8201, further comprising amagnetometer and an inclinometer coupled to the drilling apparatus, themagnetometer being configured to sense a magnetic field formed by atleast one of the magnetic segments, wherein the system is configured tocontrol the drilling apparatus based on, at least in part, sensedreadings from the magnetometer and the inclinometer.
 8219. The system ofclaim 8201, wherein the magnetic string is positioned in a linear array.8220. A method for forming more than one wellbore in a hydrocarboncontaining formation, comprising: forming a first wellbore in aformation; placing a magnetic string in the first wellbore, wherein themagnetic string produces two or more magnetic fields in a portion of theformation; forming a first set of one or more wellbores proximate to thefirst wellbore using, at least in part, one or more magnetic fieldsproduced by the magnetic string; moving the magnetic string from thefirst wellbore to a wellbore in the first set of one or more wellbores;and forming a second set of one or more wellbores proximate to thewellbore with the magnetic string.
 8221. The method of claim 8220,further comprising forming a third set of one or more wellboresproximate to a wellbore in the second set of one or more wellboresusing, at least in part, the magnetic string, wherein the magneticstring has been moved to the wellbore in the second set of one or morewellbores.
 8222. The method of claim 8220, further comprising usingmagnetic tracking of two or more magnetic fields to space a wellborebeing formed at an approximate desired distance from the first wellbore.8223. The method of claim 8220, further comprising using a magnetometerin a wellbore being formed, and at least one magnetic field, to spacesuch wellbore being formed at an approximate desired distance from thefirst wellbore.
 8224. The method of claim 8220, further comprising usinga magnetometer and an inclinometer in a wellbore being formed, and atleast one magnetic field, to space such wellbore being formed at anapproximate desired distance from the first wellbore.
 8225. The methodof claim 8220, further comprising forming a third set of one or morewellbores proximate to a wellbore in the first set of one or morewellbores using the magnetic string, wherein the magnetic string hasbeen moved to the wellbore in the first set of one or more wellbores,and wherein the wellbore is a different wellbore than the wellbore usedto form the second set of one or more wellbores.
 8226. The method ofclaim 8220, further comprising forming a pattern of wellbores in thehydrocarbon containing formation.
 8227. The method of claim 8220,further comprising forming a triangular pattern of wellbores in thehydrocarbon containing formation.
 8228. The method of claim 8220,further comprising forming a seven spot pattern of wellbores in thehydrocarbon containing formation.
 8229. The method of claim 8220,wherein a deviation in a spacing between each of the formed wellbores isless than or equal to about ±1 m.
 8230. The method of claim 8220,wherein a deviation in a spacing between each of the formed wellbores isless than or equal to about ±0.5 m.
 8231. The method of claim 8220,further comprising placing a heating mechanism in a portion of at leastone wellbore.
 8232. The method of claim 8220, further comprising formingat least one production wellbore in the hydrocarbon containingformation.
 8233. The method of claim 8220, wherein at least one heateris placed in at least one wellbore in the formation, and wherein theheater can be used in a method comprising: providing heat from the atleast one heater to a portion of the formation; pyrolyzing at least somehydrocarbons in the formation; and producing a mixture from theformation, wherein the mixture comprises at least some pyrolyzedhydrocarbons.
 8234. A method for forming one or more openings below theearth's surface, comprising: forming a first opening in the earth'ssurface; providing at least one movable permanent longitudinal magnet inthe first opening, wherein at least one movable permanent longitudinalmagnet has a north pole and a south pole, and wherein a longitudinalaxis of the magnet is substantially parallel or coaxial with alongitudinal axis of the portion of the first opening that is proximateto the at least one movable permanent longitudinal magnet; and forming asecond opening in the formation using one or more magnetic fieldsproduced by the magnet such that the second opening is spaced at anapproximate desired distance from the first opening.
 8235. The method ofclaim 8234, wherein substantially parallel comprises within about 5% ofparallel.
 8236. The method of claim 8234, further comprising usingmagnetic tracking of one or more of the magnetic fields to space thesecond opening at an approximate desired distance from the firstopening.
 8237. The method of claim 8234, further comprising using amagnetometer in the second opening, and one or more of the magneticfields, to space the second opening at an approximate desired distancefrom the first opening.
 8238. The method of claim 8234, furthercomprising using a magnetometer and an inclinometer in the secondopening, and one or more of the magnetic fields, to space the secondopening at an approximate desired distance from the first opening. 8239.The method of claim 8234, wherein at least one movable permanentlongitudinal magnet comprises aluminum, cobalt, and nickel.
 8240. Themethod of claim 8234, wherein at least one movable permanentlongitudinal magnet is positioned in a casing.
 8241. The method of claim8234, wherein at least one movable permanent longitudinal magnet ispositioned in a ferromagnetic casing.
 8242. The method of claim 8234,wherein at least one movable permanent longitudinal magnet is placed ina conduit.
 8243. The method of claim 8234, wherein a length of at leastone movable permanent longitudinal magnet is substantially similar tothe desired distance between the first opening and the second opening.8244. The method of claim 8234, further comprising moving at least onemovable permanent longitudinal magnet in the first opening to vary atleast one magnetic field with time.
 8245. The method of claim 8234,further comprising moving at least one movable permanent longitudinalmagnet in the first opening to increase a length of the second opening.8246. The method of claim 8234, further comprising forming a pluralityof openings proximate to the first opening.
 8247. The method of claim8234, wherein the first opening is a substantially vertical opening, andwherein the second opening is a substantially horizontal opening thatpasses the first opening at a selected distance from the first openingand at a selected depth in the formation.
 8248. The method of claim8234, wherein the first opening comprises a non-ferromagnetic casing.8249. The method of claim 8234, wherein the magnetic fields comprise afirst magnetic field and a second magnetic field and wherein a strengthof the first magnetic field differs from a strength of the secondmagnetic field.
 8250. The method of claim 8234, wherein the magneticfields comprise a first magnetic field and a second magnetic field andwherein a strength of the first magnetic field is about the same as astrength of the second magnetic field.
 8251. The method of claim 8234,wherein the magnetic fields comprise a pole strength between about 100Gauss and 2000 Gauss.
 8252. The method of claim 8234, wherein the firstopening comprises a center opening in a pattern of openings, the methodfurther comprising forming a plurality of openings in the pattern ofopenings proximate to the first opening.
 8253. The method of claim 8234,wherein the first opening comprises a center opening in a pattern ofopenings, the method further comprising forming a plurality of openingsin the pattern of openings proximate to the first opening, and whereineach of the plurality of openings is spaced at an approximate desireddistance from the first opening.
 8254. The method of claim 8234, furthercomprising providing at least one heating mechanism in the first openingand at least one heating mechanism in the second opening such that theheating mechanisms can be used to provide heat to at least a portion ofthe formation.
 8255. The method of claim 8234, wherein a deviation inthe spacing between the second opening and the first opening is lessthan or equal to about ±1 m.
 8256. The method of claim 8234, wherein adeviation in the spacing between the second opening and the firstopening is less than or equal to about ±0.5 m.
 8257. The method of claim8234, further comprising measuring a magnetic field when at least onemovable permanent longitudinal magnet is at a first position, moving theat least one movable permanent longitudinal magnet, measuring a magneticfield when the at least one movable permanent longitudinal magnet is ata second position, and wherein measurements at the two positions areused to calibrate for an effect of other magnetic fields.
 8258. Themethod of claim 8257, wherein at least two positions comprise positionsspaced apart by multiples of L/4, and wherein L is a length of at leastone movable permanent longitudinal magnet.
 8259. The method of claim8234, wherein a measurement of the magnetic fields is taken at twopositions separated by L/2 along a length of at least one movablepermanent longitudinal magnet in the first opening to reduce an effectof fixed magnetic fields on a determination of distance between thefirst opening and the second opening, and wherein L is a length of atleast one movable permanent longitudinal magnet.
 8260. The method ofclaim 8234, wherein at least one movable permanent longitudinal magnetis positioned in a linear array.
 8261. The method of claim 8234, whereinat least one heater is placed in at least one opening in the formation,and wherein the heater can be used in a method comprising: providingheat from the at least one heater to a portion of the formation;pyrolyzing at least some hydrocarbons in the formation; and producing amixture from the formation, wherein the mixture comprises at least somepyrolyzed hydrocarbons.
 8262. A method for forming one or more openingsbelow the earth's surface, comprising: forming a first opening below theearth's surface; providing a conduit in the first opening, wherein theconduit is positioned along at least a portion of the first opening;providing an electric current to the conduit to produce a magnetic fieldalong at least a portion of the conduit; and forming a second openingbelow the earth's surface using the magnetic field, wherein the magneticfield is used such that the second opening is spaced at an approximatedesired distance from the first opening.
 8263. The method of claim 8262,wherein the first opening and the second opening are formed in ahydrocarbon containing formation.
 8264. The method of claim 8262,wherein the first opening comprises a first end at a first surfacelocation and a second end at a second surface location.
 8265. The methodof claim 8262, further comprising using magnetic tracking of themagnetic field to space the second opening at an approximate desireddistance from the first opening.
 8266. The method of claim 8262, furthercomprising using a magnetometer in the second opening, and the magneticfield, to space the second opening at an approximate desired distancefrom the first opening.
 8267. The method of claim 8262, furthercomprising using a magnetometer and an inclinometer in the secondopening, and the magnetic field, to space the second opening at anapproximate desired distance from the first opening.
 8268. The method ofclaim 8262, wherein the conduit comprises a casing in the first opening.8269. The method of claim 8262, wherein the conduit is configured topropagate the electric current and, in addition, serve as a barrier inthe first opening, or serve to conduct one or more fluids in the firstopening.
 8270. The method of claim 8262, further comprising coupling anelectrical conductor to a first end of the conduit, and coupling anelectrical conductor to a second end of the conduit, wherein theelectrical conductors are on or proximate the surface of the earth.8271. The method of claim 8262, further comprising coupling a source ofcurrent to the conduit or to an electrical conductor, wherein theelectrical conductor is coupled to a first end of the conduit, or to asecond end of the conduit, and wherein the electrical conductor is on orproximate the surface of the earth.
 8272. The method of claim 8262,wherein the first opening comprises a first end at a first surfacelocation and a second end at a second surface location, and furthercomprising coupling an electrical conductor to a first end of theconduit, and coupling an electrical conductor to a second end of theconduit, and wherein the electrical conductors are on or proximate thesurface of the earth.
 8273. The method of claim 8262, wherein the firstopening comprises a first end at a first surface location and a secondend at a second surface location, and further comprising coupling asource of current to the conduit or to an electrical conductor, whereinthe electrical conductor is coupled to a first end of the conduit, or toa second end of the conduit, wherein the electrical conductor is on orproximate the surface of the earth.
 8274. The method of claim 8262,further comprising grounding the electrical current below the earth'ssurface.
 8275. The method of claim 8262, wherein the second openingcomprises a first end at a first surface location and a second end at asecond surface location.
 8276. The method of claim 8262, wherein theelectrical current is provided in a forward direction through theconduit for a first time period to produce a first magnetic field, andthen the current is provided in a reverse direction through the conduitfor a second time period to produce a second magnetic field, and whereinsubtraction between the first and second magnetic fields reduces aneffect from fixed magnetic fields.
 8277. The method of claim 8262,wherein the electrical current is provided from a DC current source.8278. The method of claim 8262, wherein an electro-insulating materialis placed on at least a portion of the conduit.
 8279. The method ofclaim 8262, wherein an electro-insulating material is placed on at leasta portion of the conduit, and wherein the electro-insulating material isadapted to melt, vaporize, and/or oxidize when heated.
 8280. The methodof claim 8262, wherein the conduit is a heater conduit configured toprovide or transfer heat to at least a portion of a hydrocarboncontaining formation.
 8281. The method of claim 8262, further comprisingforming a plurality of openings in the vicinity of the first opening.8282. The method of claim 8262, further comprising forming a thirdopening below the earth's surface using the magnetic field such that thethird opening is spaced at an approximate desired distance from thefirst opening or the second opening.
 8283. The method of claim 8262,further comprising forming a third opening below the earth's surfaceusing the magnetic field such that the third opening is spaced at anapproximate desired distance from the first opening, and wherein thedesired distance between the first opening and the third opening isabout 1.5 to 3 times the desired distance between the first opening andthe second opening.
 8284. The method of claim 8262, wherein the firstopening is a center opening in a pattern of openings, the method furthercomprising forming a plurality of openings in the pattern of openingsproximate to the first opening.
 8285. The method of claim 8262, whereinthe first opening is a center opening in a pattern of openings, themethod further comprising forming a plurality of openings in the patternof openings proximate to the first opening, and wherein each of theplurality of openings is spaced at an approximate desired distance fromthe first opening.
 8286. The method of claim 8262, further comprisingproviding at least one heating mechanism in the first opening and atleast one heating mechanism in the second opening such that the heatingmechanisms can be used to provide heat to at least a portion of ahydrocarbon containing formation.
 8287. The method of claim 8262,wherein a deviation in the spacing between the second opening and thefirst opening is less than or equal to about ±1 m.
 8288. The method ofclaim 8262, wherein a deviation in the spacing between the secondopening and the first opening is less than or equal to about ±0.5 m.8289. The method of claim 8262, wherein at least one heater is placed inat least one opening in a hydrocarbon containing formation, and whereinthe heater can be used in a method comprising: providing heat from theat least one heater to a portion of the formation; pyrolyzing at leastsome hydrocarbons in the formation; and producing a mixture from theformation, wherein the mixture comprises at least some pyrolyzedhydrocarbons.
 8290. A method for forming a wellbore and installing aheater in a hydrocarbon containing formation, comprising: forming anopening in the formation, wherein the opening comprises a first end thatcontacts the earth's surface at a first location and a second end thatcontacts the earth's surface at a second location; and placing a heaterin or coupled to the opening, wherein the heater is configured toprovide or transfer heat to at least a portion of the formation topyrolyze at least some hydrocarbons in the formation.
 8291. The methodof claim 8290, wherein the opening comprises a portion that is formedsubstantially horizontally in a hydrocarbon layer of the formation.8292. The method of claim 8290, further comprising forming the first endof the opening at an angle with respect to the earth's surface, whereinthe angle is between about 5° and about 20°.
 8293. The method of claim8290, further comprising forming the second end of the opening at anangle with respect to the earth's surface, wherein the angle is betweenabout 5° and about 20°.
 8294. The method of claim 8290, wherein thefirst end and the second end of the opening comprise portions of theopening located substantially in the overburden of the formation. 8295.The method of claim 8290, wherein the first end and the second end ofthe opening comprise portions of the opening located substantially inthe overburden of the formation, the method further comprising placingreinforcing material in the portions of the opening in the overburden.8296. The method of claim 8290, wherein forming the opening comprisesdrilling an opening from the first end of the opening towards the secondend of the opening using machinery located at the first end of theopening.
 8297. The method of claim 8290, further comprising reaming outthe opening.
 8298. The method of claim 8290, wherein the heater isplaced in the opening by pulling the heater from the second end of theopening towards the first end of the opening with machinery located atthe first end of the opening.
 8299. The method of claim 8290, whereinthe heater is coupled to a drill bit used to form the opening, andwherein the heater is placed in the opening by pulling the heatercoupled to the drill bit from the second end of the opening towards thefirst end of the opening with machinery located at the first end of theopening.
 8300. The method of claim 8290, wherein the heater is laid outon the surface of the formation before the heater is placed in theopening.
 8301. The method of claim 8290, wherein the heater is unspooledon the surface of the formation as the heater is placed in the opening.8302. The method of claim 8290, further comprising reaming out theopening while pulling a heater from the second end of the openingtowards the first end of the opening with machinery located at the firstend of the opening.
 8303. The method of claim 8290, wherein the heatercomprises at least one oxidizer located in the opening.
 8304. The methodof claim 8290, wherein the heater comprises at least one oxidizerlocated on the surface, and coupled to the opening.
 8305. The method ofclaim 8290, further comprising forming a second opening in the formationusing, at least in part, a magnetic field produced in the opening in theformation, wherein the second opening comprises a first end thatcontacts the earth's surface at a first location and a second end thatcontacts the earth's surface at a second location.
 8306. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters placed in, or coupled to, one ormore openings in the formation to at least one part of the formation,wherein at least one opening comprises a first end that contacts theearth's surface at a first location and a second end that contacts theearth's surface at a second location; allowing the heat to transfer fromthe one or more heaters to a part of the formation to substantiallypyrolyze at least a portion of the formation; and producing a mixturefrom the formation, wherein the mixture comprises at least somepyrolyzation products.
 8307. The method of claim 8306, wherein at leastone opening has been formed by drilling the opening from the first endof the opening towards the second end of the opening using machinerylocated at the first end of the opening.
 8308. The method of claim 8306,wherein at least one heater is placed in at least one opening by pullingthe heater from the second end of the opening towards the first end ofthe opening with machinery located at the first end of the opening.8309. The method of claim 8306, wherein at least one heater is coupledto a drill bit used to form at least one opening, and wherein the atleast one heater is placed in the at least one opening by pulling theheater coupled to the drill bit from the second end of the openingtowards the first end of the opening with machinery located at the firstend of the opening.
 8310. The method of claim 8306, wherein at least oneopening comprises a portion that is formed substantially horizontally ina hydrocarbon layer of the formation.
 8311. The method of claim 8306,wherein the first end of the opening is formed at an angle with respectto the earth's surface, and wherein the angle is between about 5° andabout 20°.
 8312. The method of claim 8306, wherein the second end of theopening is formed at an angle with respect to the earth's surface, andwherein the angle is between about 5° and about 20°.
 8313. The method ofclaim 8306, further comprising maintaining a temperature in at least aportion of the formation in a pyrolysis temperature range with a lowerpyrolysis temperature of about 250° C. and an upper pyrolysistemperature of about 400° C.
 8314. The method of claim 8306, furthercomprising heating at least a part of the formation to substantiallypyrolyze at least a majority of the hydrocarbons in the formation in aselected section of the formation.
 8315. The method of claim 8306,further comprising controlling a pressure and a temperature in at leasta part of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 8316. The method of claim 8306, wherein allowing the heatto transfer from the one or more heaters to the part of the formationcomprises transferring heat substantially by conduction.
 8317. Themethod of claim 8306, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 8318. Themethod of claim 8306, further comprising controlling a pressure in atleast a majority of a part of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 8319. The method of claim8306, further comprising controlling formation conditions such that theproduced mixture comprises a partial pressure of H₂ in the mixturegreater than about 0.5 bars.
 8320. A system configurable to heat ahydrocarbon containing formation, comprising: a container configurableto be placed in an opening in the formation, wherein the container isconfigurable to be pressurized to inhibit deformation of the containerduring use; a conductor configurable such that at least a portion of theconductor can be placed in the container, wherein the conductor isfurther configurable to provide heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer from the conductor to a section of the formation duringuse.
 8321. The system of claim 8320, further comprising a lead-inconductor configurable to be electrically coupled to the conductorduring use, wherein the lead-in conductor is further configurable to beat least partially placed in the formation overburden.
 8322. The systemof claim 8320, further comprising a lead-in conductor configurable to beelectrically coupled to the conductor during use, wherein the lead-inconductor is further configurable supply electrical power to theconductor during use.
 8323. The system of claim 8320, further comprisinga lead-in conductor configurable to be electrically coupled to theconductor during use, and a feedthrough configurable to allow thelead-in conductor to pass through the container.
 8324. The system ofclaim 8320, further comprising a lead-in conductor configurable to beelectrically coupled to the conductor during use, wherein the lead-inconductor is at least partially insulated and comprises copper. 8325.The system of claim 8320, further comprising a seal on the containerconfigurable to enclose at least a portion of the conductor in thecontainer, wherein the seal is further configurable to maintain apressure in the container.
 8326. The system of claim 8320, furthercomprising a lead-out conductor configurable to be coupled to thecontainer.
 8327. The system of claim 8320, further comprising a lead-outconductor configurable to be coupled to the container, wherein thelead-out conductor comprises an insulated copper conductor.
 8328. Thesystem of claim 8320, wherein the system is further configurable topyrolyze at least some hydrocarbons in the heated section of theformation during use.
 8329. The system of claim 8320, wherein thecontainer comprises a conduit.
 8330. The system of claim 8320, whereinthe system is configured to heat a hydrocarbon containing formation, thesystem comprising: a container placed in an opening in the formation,wherein the conduit is pressurized to inhibit deformation of thecontainer during use; a conductor at least partially in the container,wherein the conductor is further configured to provide heat to at leasta portion of the formation during use; and wherein the system isconfigured to allow heat to transfer from the conductor to a section ofthe formation during use.
 8331. An in situ method for heating ahydrocarbon containing formation, comprising: applying an electricalcurrent to a conductor to provide heat to at least a portion of theformation, wherein the conductor is at least partially placed in acontainer, wherein the container is in an opening in the formation, andwherein the container is pressurized to inhibit deformation of thecontainer; allowing the heat to transfer from the conductor to at leasta part of the formation.
 8332. The method of claim 8331, wherein alead-in conductor is electrically coupled to the conductor, and whereinthe lead-in conductor is at least partially in the formation overburden.8333. The method of claim 8331, wherein the container comprises aconduit.
 8334. The method of claim 8331, further comprising supplyingelectrical power to the conductor through a lead-in conductorelectrically coupled to the conductor.
 8335. The method of claim 8331,wherein a lead-in conductor is electrically coupled to the conductor,and wherein the lead-in conductor is at least partially insulated andcomprises copper.
 8336. The method of claim 8331, further comprisingenclosing the conductor in the conduit with a seal on the conduit,wherein the seal maintains a pressure in the conduit.
 8337. The methodof claim 8331, further comprising pyrolyzing at least some hydrocarbonsin the formation.
 8338. The method of claim 8331, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the pressure is controlled as a function oftemperature.
 8339. The method of claim 8331, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the temperature is controlled as a function ofpressure.
 8340. The method of claim 8331, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.8341. The method of claim 8331, further comprising controlling apressure in at least a part of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 8342. The method of claim8331, further comprising controlling formation conditions such that aproduced mixture comprises a partial pressure of H₂ in the mixturegreater than about 0.5 bars.
 8343. The method of claim 8331, furthercomprising altering a pressure in the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 8344. The method of claim 8331, wherein at least a portion of thepart of the formation is heated to a minimum pyrolysis temperature ofabout 270° C.
 8345. A system configurable to heat a hydrocarboncontaining formation, comprising: a conduit configurable to be placed inan opening in the formation; a conductor configurable to be at leastpartially placed in a conduit, wherein the conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use; a sliding connector configurable to be coupled to theconductor and the conduit, wherein the sliding connector is configurableto electrically couple the conduit to a lead-out conductor; and whereinthe system is configurable to allow heat to transfer from the conductorto a section of the formation during use.
 8346. The system of claim8345, further comprising one or more insulators configurable toelectrically insulate the conductor from the conduit.
 8347. The systemof claim 8345, further comprising one or more ceramic insulatorsconfigurable to electrically insulate the conductor from the conduit.8348. The system of claim 8345, further comprising a lead-in conductorconfigurable to be electrically coupled to the conductor during use,wherein the lead-in conductor is further configurable to be at leastpartially placed in the formation overburden.
 8349. The system of claim8345, further comprising a lead-in conductor configurable to beelectrically coupled to the conductor during use, wherein the lead-inconductor is further configurable supply electrical power to theconductor during use.
 8350. The system of claim 8345, wherein thelead-out conductor comprises an insulated copper conductor.
 8351. Thesystem of claim 8345, wherein the system is further configurable topyrolyze at least some hydrocarbons in the heated section of theformation during use.
 8352. The system of claim 8345, wherein the systemis configured to heat a hydrocarbon containing formation, the systemcomprising: a conduit placed in an opening in the formation; a conductorplaced in a conduit, wherein the conductor is further configured toprovide heat to at least a portion of the formation during use; asliding connector coupled to the conductor and the conduit, wherein thesliding connector electrically couples the conduit to a lead-outconductor; and wherein the system is configured to allow heat totransfer from the conductor to a section of the formation during use.8353. An in situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to a conductor to provideheat to at least a portion of the formation, wherein the conductor is atleast partially placed in a conduit, wherein a sliding connector iscoupled to the conductor and the conduit, and wherein the slidingconnector electrically couples the conduit to a lead-out conductor; andallowing the heat to transfer from the conductor to at least a part ofthe formation.
 8354. The method of claim 8353, wherein the slidingconnector is electrically insulated from the conductor with one or moreinsulators.
 8355. The method of claim 8353, wherein a lead-in conductoris electrically coupled to the conductor, and wherein the lead-inconductor is least partially placed in the formation overburden. 8356.The method of claim 8353, further comprising supplying electrical powerto the conductor through a lead-in conductor electrically coupled to theconductor.
 8357. The method of claim 8353, wherein the lead-outconductor comprises an insulated copper conductor.
 8358. The method ofclaim 8353, further comprising pyrolyzing at least some hydrocarbons inthe formation.
 8359. The method of claim 8353, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the pressure is controlled as a function oftemperature.
 8360. The method of claim 8353, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the temperature is controlled as a function ofpressure.
 8361. The method of claim 8353, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.8362. The method of claim 8353, further comprising controlling apressure in at least a majority of the part of the formation, whereinthe controlled pressure is at least about 2.0 bars absolute.
 8363. Themethod of claim 8353, further comprising controlling formationconditions such that a produced mixture comprises a partial pressure ofH₂ in the mixture greater than about 0.5 bars.
 8364. The method of claim8353, further comprising altering a pressure in the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 8365. The method of claim 8353, wherein at leasta portion of the part of the formation is heated to a minimum pyrolysistemperature of about 270° C.
 8366. The method of claim 8353, wherein thesliding connector is at least partially flexible.
 8367. A systemconfigured to heat at least a part of a hydrocarbon containingformation, comprising: a conductor configurable to be placed within anopening in the formation, wherein the conductor is further configurableto provide heat to at least a part of the formation during use; a firstelectrically conductive material configurable to be coupled to at leasta portion of the conductor, wherein the first electrically conductivematerial is configurable to lower an electrical resistance of at leastpart of the conductor when such conductor is in formation overburdenduring use; and wherein the system is configurable to allow heat totransfer from the conductor to at least a part of the formation duringuse.
 8368. The system of claim 8367, wherein the conductor is configuredto be placed in a conduit, and the conduit is configurable to be placedin the opening in the formation.
 8369. The system of claim 8368, furthercomprising a second electrically conductive material configurable to becoupled to at least a portion of an inside surface of the conduit. 8370.The system of claim 8367, further comprising a low resistance conductorconfigurable to be electrically coupled to the conductor during use,wherein the substantially low resistance conductor is furtherconfigurable to be placed within the formation overburden.
 8371. Thesystem of claim 8369, wherein the low resistance conductor comprisescarbon steel.
 8372. The system of claim 8367, wherein the electricallyconductive material comprises metal tubing or strips configurable to beclad, at least in part, to the conductor.
 8373. The system of claim8367, wherein the electrically conductive material comprises metaltubing or strips configurable to be clad, at least in part, to anelectrically conductive coating configurable to be applied to theconductor.
 8374. The system of claim 8367, wherein the electricallyconductive material comprises metal tubing or strips configurable to beclad, at least in part, to a thermal plasma applied coating.
 8375. Thesystem of claim 8367, wherein the electrically conductive materialcomprises aluminum.
 8376. The system of claim 8367, wherein theelectrically conductive material comprises copper.
 8377. The system ofclaim 8367, wherein the electrically conductive material is configurableto reduce the electrical resistance of the conductor in the overburdenby a factor of greater than about
 3. 8378. The system of claim 8367,wherein the electrically conductive material is configurable to reducethe electrical resistance of the conductor in the overburden by a factorof greater than about
 10. 8379. The system of claim 8367, wherein theelectrically conductive material is configurable to reduce theelectrical resistance of the conductor in the overburden by a factor ofgreater than about
 15. 8380. The system of claim 8367, wherein thesystem is further configurable to pyrolyze at least some hydrocarbons inthe heated section of the formation during use.
 8381. An in situ methodfor heating a hydrocarbon containing formation, comprising: applying anelectrical current to a conductor to provide heat to at least a portionof the formation, wherein the conductor is configurable to be placedwithin an opening in the formation, wherein at least part of theconductor is coupled to a first electrically conductive material tolower a resistance of the part of the conductor in a formationoverburden; and allowing the heat to transfer from the conductor to atleast a part of the formation.
 8382. The method of claim 8381, furthercomprising placing the conductor in a conduit, wherein the conduit isconfigurable to be placed in the opening in the formation.
 8383. Themethod of claim 8382, further comprising coupling a second electricallyconductive material to at least a portion of an inside surface of theconduit.
 8384. The method of claim 8381, further comprising reducing theelectrical resistance of the conductor in the overburden by a factor ofgreater than about 3 with the electrically conductive material. 8385.The method of claim 8381, further comprising reducing the electricalresistance of the conductor in the overburden by a factor of greaterthan about 10 with the electrically conductive material.
 8386. Themethod of claim 8381, further comprising reducing the electricalresistance of the conductor in the overburden by a factor of greaterthan about 15 with the electrically conductive material.
 8387. Themethod of claim 8381, further comprising pyrolyzing at least somehydrocarbons within the formation.
 8388. The method of claim 8381,further comprising controlling a pressure and a temperature within atleast a majority of the part of the formation, wherein the pressure iscontrolled as a function of temperature.
 8389. The method of claim 8381,further comprising controlling a pressure and a temperature within atleast a majority of the part of the formation, wherein the temperatureis controlled as a function of pressure.
 8390. The method of claim 8381,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8391. The method of claim 8381, furthercomprising controlling a pressure within at least a majority of the partof the formation, wherein the controlled pressure is at least about 2.0bars absolute.
 8392. The method of claim 8381, further comprisingcontrolling formation conditions such that a produced mixture comprisesa partial pressure of H₂ within the mixture greater than about 0.5 bars.8393. The method of claim 8381, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 8394. The methodof claim 8381, wherein at least a portion of the part of the formationis heated to a minimum pyrolysis temperature of about 270° C.
 8395. Asystem configurable to heat a hydrocarbon containing formation,comprising: a conduit configured to be placed within an opening in theformation; a conductor configured to be placed within a conduit, whereinthe conductor is further configured to provide heat to at least aportion of the formation during use; an electrically conductive materialconfigured to be electrically coupled to the conductor, wherein theelectrically conductive material is further configured to propagate amajority of electrical current, in the overburden, provided to theconductor during use; and wherein the system is configured to allow heatto transfer from the conductor to a section of the formation during use.8396. The system of claim 8395, further comprising a second electricallyconductive material configurable to be coupled to at least a portion ofan inside surface of the conduit.
 8397. The system of claim 8395,further comprising a low resistance conductor configurable to beelectrically coupled to the conductor during use, wherein thesubstantially low resistance conductor is further configurable to beplaced within the formation overburden.
 8398. The system of claim 8397,wherein the low resistance conductor comprises carbon steel.
 8399. Thesystem of claim 8395, wherein the electrically conductive materialcomprises metal tubing or strips configurable to be clad, at least inpart, to the conductor.
 8400. The system of claim 8395, wherein theelectrically conductive material comprises metal tubing or stripsconfigurable to be clad, at least in part, to an electrically conductivecoating configurable to be applied to the conductor.
 8401. The system ofclaim 8395, wherein the electrically conductive material comprises metaltubing or strips configurable to be clad, at least in part, to a thermalplasma applied coating.
 8402. The system of claim 8395, wherein theelectrically conductive material comprises aluminum.
 8403. The system ofclaim 8395, wherein the electrically conductive material comprisescopper.
 8404. The system of claim 8395, wherein the electricallyconductive material is configurable to reduce the electrical resistanceof the conductor in the overburden by a factor of greater than about 3.8405. The system of claim 8395, wherein the electrically conductivematerial is configurable to reduce the electrical resistance of theconductor in the overburden by a factor of greater than about
 10. 8406.The system of claim 8395, wherein the electrically conductive materialis configurable to reduce the electrical resistance of the conductor inthe overburden by a factor of greater than about
 15. 8407. The system ofclaim 8395, wherein the system is further configurable to pyrolyze atleast some hydrocarbons in the heated section of the formation duringuse.
 8408. An in situ method for heating a hydrocarbon containingformation, comprising: applying an electrical current to a conductor toprovide heat to at least a portion of the formation, wherein theconductor is configurable to be placed within a conduit, wherein theconduit is configurable to be placed in an opening in the formation,wherein at least part of the conductor in a formation overburden iscoupled to a first electrically conductive material so that a majorityof the electrical current provided to the conductor flows through thefirst electrically conductive material in the formation overburden; andallowing the heat to transfer from the conductor to at least a part ofthe formation.
 8409. The method of claim 8408, further comprisingcoupling a second electrically conductive material to at least a portionof an inside surface of the conduit.
 8410. The method of claim 8408,further comprising reducing the electrical resistance of the conductorin the overburden by a factor of greater than about 3 with theelectrically conductive material.
 8411. The method of claim 8408,further comprising reducing the electrical resistance of the conductorin the overburden by a factor of greater than about 10 with theelectrically conductive material.
 8412. The method of claim 8408,further comprising reducing the electrical resistance of the conductorin the overburden by a factor of greater than about 15 with theelectrically conductive material.
 8413. The method of claim 8408,further comprising pyrolyzing at least some hydrocarbons within theformation.
 8414. The method of claim 8408, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe part of the formation, wherein the pressure is controlled as afunction of temperature.
 8415. The method of claim 8408, furthercomprising controlling a pressure and a temperature within at least amajority of the part of the formation, wherein the temperature iscontrolled as a function of pressure.
 8416. The method of claim 8408,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8417. The method of claim 8408, furthercomprising controlling a pressure within at least a majority of the partof the formation, wherein the controlled pressure is at least about 2.0bars absolute.
 8418. The method of claim 8408, further comprisingcontrolling formation conditions such that a produced mixture comprisesa partial pressure of H₂ within the mixture greater than about 0.5 bars.8419. The method of claim 8408, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 8420. The methodof claim 8408, wherein at least a portion of the part of the formationis heated to a minimum pyrolysis temperature of about 270° C.
 8421. Amethod for treating a hydrocarbon containing formation, comprising:providing heat from one or more heaters to at least a portion of theformation, wherein at least one heater is in at least one open wellborein the formation, and wherein heating from one or more heaters iscontrolled to inhibit substantial deformation of one or more heaterscaused by thermal formation expansion against such one or more heaters;allowing the heat to transfer from the one or more heaters to a part ofthe formation; and producing a mixture from the formation.
 8422. Themethod of claim 8421, further comprising controlling the heating tomaintain a minimum space between at least one heater and the formationin at least one open wellbore.
 8423. The method of claim 8421, furthercomprising controlling the heating to maintain a minimum space of atleast about 0.25 cm between at least one heater and the formation in atleast one open wellbore.
 8424. The method of claim 8421, wherein atleast one heater is in an open wellbore having a diameter sufficient toinhibit the formation from expanding against such heater during heatingof the formation.
 8425. The method of claim 8424, wherein the diameterof the open wellbore is greater than or equal to about 30 cm.
 8426. Themethod of claim 8421, wherein one or more of the open wellbores have anexpanded diameter proximate to relatively rich zones in the formation.8427. The method of claim 8426, wherein one or more of the expandeddiameters is greater than or equal to about 30 cm.
 8428. The method ofclaim 8426, wherein the relatively rich zones comprise a richnessgreater than about 0.15 L/kg.
 8429. The method of claim 8426, whereinthe relatively rich zones comprise a richness greater than about 0.17L/kg.
 8430. The method of claim 8421, wherein controlling the heatingcomprises adjusting a heat output of at least one heater such that theheat output provided to relatively rich zones of the formation is lessthan the heat output provided to other zones of the formation.
 8431. Themethod of claim 8421, wherein controlling the heating comprisesadjusting a heat output of at least one heater such that about the heatoutput provided to relatively rich zones of the formation is less thanabout ½ the heat output provided to other zones of the formation. 8432.The method of claim 8431, wherein the relatively rich zones comprise arichness greater than about 0.15 L/kg.
 8433. The method of claim 8421,further comprising reaming at least one open wellbore after at leastsome heating of the formation from the wellbore being reamed.
 8434. Themethod of claim 8421, further comprising reaming at least one openwellbore after at least some heating of the formation from the wellborebeing reamed, and wherein the reaming is conducted to remove at leastsome hydrocarbon material that has expanded in the open wellbore. 8435.The method of claim 8421, further comprising removing at least oneheater from at least one open wellbore, and then reaming at least onesuch open wellbore.
 8436. The method of claim 8421, further comprisingperforating one or more relatively rich zones in at least part of theformation to allow for expansion of at least one or more of therelatively rich zones during heating of the formation.
 8437. The methodof claim 8421, further comprising placing a liner in at least one openwellbore and between at least a part of a heater and the formation,wherein the liner inhibits heater deformation caused by thermalformation expansion during heating.
 8438. The method of claim 8437,wherein the liner comprises a mechanical strength sufficient to inhibitcollapsing of the liner proximate relatively rich zones of theformation.
 8439. The method of claim 8437, wherein the liner comprisesone or more openings to allow fluids to flow through the open wellbore.8440. The method of claim 8421, further comprising maintaining atemperature in at least a portion of the formation in a pyrolysistemperature range with a lower pyrolysis temperature of about 250° C.and an upper pyrolysis temperature of about 400° C.
 8441. The method ofclaim 8421, further comprising heating at least a part of the formationto substantially pyrolyze at least some of the hydrocarbons in theformation.
 8442. The method of claim 8421, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.8443. The method of claim 8421, wherein allowing the heat to transferfrom the one or more heaters to the part of the formation comprisestransferring heat substantially by conduction.
 8444. The method of claim8421, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 8445. The method of claim8421, further comprising controlling a pressure in at least a majorityof a part of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 8446. The method of claim 8421, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ in the mixture greater thanabout 0.5 bars.
 8447. A method for treating a hydrocarbon containingformation, comprising: providing heat from one or more heaters to atleast a portion of the formation, wherein at least one heater is in atleast one open wellbore in the formation, and wherein at least one openwellbore has been sized, at least in part, based on a determination offormation expansion caused by heating of the formation such thatformation expansion caused by heating of the formation is not sufficientto cause substantial deformation of one or more heaters in such sizedwellbores; allowing the heat to transfer from the one or more heaters toa part of the formation; and producing a mixture from the formation.8448. The method of claim 8447, further comprising controlling theheating to maintain a minimum space between at least one heater and theformation in at least one open wellbore.
 8449. The method of claim 8447,further comprising controlling the heating to maintain a minimum spaceof at least about 0.25 cm between at least one heater and the formationin at least one open wellbore.
 8450. The method of claim 8447, whereinat least one heater is in an open wellbore having a diameter sufficientto inhibit the formation from expanding against such heater duringheating of the formation.
 8451. The method of claim 8450, wherein thediameter of one or more of the sized open wellbores is greater than orequal to about 30 cm.
 8452. The method of claim 8447, wherein one ormore of the open wellbores have an expanded diameter proximate torelatively rich zones in the formation.
 8453. The method of claim 8452,wherein one or more of the expanded diameters is greater than or equalto about 30 cm.
 8454. The method of claim 8452, wherein the relativelyrich zones comprise a richness greater than about 0.15 L/kg.
 8455. Themethod of claim 8452, wherein the relatively rich zones comprise arichness greater than about 0.17 L/kg.
 8456. The method of claim 8447,further comprising adjusting a heat output of at least one heater suchthat the heat output provided to relatively rich zones of the formationis less than the heat output provided to other zones of the formation.8457. The method of claim 8447, further comprising adjusting a heatoutput of at least one heater such that about the heat output providedto relatively rich zones of the formation is less than about ½ the heatoutput provided to other zones of the formation.
 8458. The method ofclaim 8456, wherein the relatively rich zones comprise a richnessgreater than about 0.15 L/kg.
 8459. The method of claim 8447, furthercomprising reaming at least one open wellbore after at least someheating of the formation from the wellbore being reamed.
 8460. Themethod of claim 8447, further comprising reaming at least one openwellbore after at least some heating of the formation from the wellborebeing reamed, and wherein the reaming is conducted to remove at leastsome hydrocarbon material that has expanded in the open wellbore. 8461.The method of claim 8447, further comprising removing at least oneheater from at least one open wellbore, and then reaming at least onesuch open wellbore.
 8462. The method of claim 8447, further comprisingperforating one or more relatively rich zones in at least part of theformation to allow for expansion of at least one or more of therelatively rich zones during heating of the formation.
 8463. The methodof claim 8447, further comprising placing a liner in at least one openwellbore and between at least a part of a heater and the formation,wherein the liner inhibits heater deformation caused for thermalformation expansion during heating.
 8464. The method of claim 8463,wherein the liner comprises a mechanical strength sufficient to inhibitcollapsing of the liner proximate relatively rich zones of theformation.
 8465. The method of claim 8463, wherein the liner comprisesone or more openings to allow fluids to flow through the open wellbore.8466. The method of claim 8447, further comprising maintaining atemperature in at least a portion of the formation in a pyrolysistemperature range with a lower pyrolysis temperature of about 250° C.and an upper pyrolysis temperature of about 400° C.
 8467. The method ofclaim 8447, further comprising heating at least a part of the formationto substantially pyrolyze at least some of the hydrocarbons in theformation.
 8468. The method of claim 8447, further comprisingcontrolling a pressure and a temperature in at least a part of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.8469. The method of claim 8447, wherein allowing the heat to transferfrom the one or more heaters to the part of the formation comprisestransferring heat substantially by conduction.
 8470. The method of claim8447, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 8471. The method of claim8447, further comprising controlling a pressure in at least a majorityof a part of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 8472. The method of claim 8447, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ in the mixture greater thanabout 0.5 bars.
 8473. A method for treating a hydrocarbon containingformation, comprising: heating a first volume of the formation using afirst set of heaters; heating a second volume of the formation using asecond set of heaters, wherein the first volume is spaced apart from thesecond volume by a third volume of the formation; heating the thirdvolume using a third set of heaters, wherein the third set of heatersbegin heating at a selected time after the first set of heaters and thesecond set of heaters; allowing the heat to transfer from the first,second, and third volumes of the formation to at least a part of theformation; and producing a mixture from the formation.
 8474. The methodof claim 8473, wherein the first, second, or third volumes are sized,shaped, or located based on, at least in part, a calculatedgeomechanical motion of at least a portion of the formation.
 8475. Themethod of claim 8473, further comprising sizing, shaping, or locatingthe first, second, or third volumes based on, at least in part, acalculated geomechanical motion of at least a portion of the formation.8476. The method of claim 8473, wherein the first, second, or thirdvolumes are sized, shaped, or located, at least in part, to inhibitdeformation, caused by geomechanical motion, of one or more selectedwellbores in the formation.
 8477. The method of claim 8473, wherein thefirst, second, or third volumes are at least in part sized, shaped, orlocated based on a calculated geomechanical motion of at least a portionof the formation, and wherein the first, second, or third volumes aresized, shaped, or located, at least in part, to inhibit deformation,caused by geomechanical motion, of one or more selected wellbores in theformation.
 8478. The method of claim 8473, wherein the first, second, orthird volume of the formation has been sized, shaped, or located, atleast in part, based on a simulation.
 8479. The method of claim 8473,wherein the first, second, and third volumes of the formation have beensized, shaped, or located, at least in part, based on a simulation.8480. The method of claim 8473, wherein a footprint area of the firstvolume, second volume, or third volume is less than about 400 squaremeters.
 8481. The method of claim 8473, wherein the third set of heatersbegin heating after a selected amount of geomechanical motion in thefirst or second volumes.
 8482. The method of claim 8473, wherein thethird set of heaters begin heating to maintain or enhance a productionrate of the mixture from the formation.
 8483. The method of claim 8473,wherein the selected time has been at least in part determined using asimulation.
 8484. The method of claim 8473, wherein the first and secondvolumes comprise rectangular footprints.
 8485. The method of claim 8473,wherein the first and second volumes comprise square footprints. 8486.The method of claim 8473, wherein the first and second volumes comprisecircular footprints.
 8487. The method of claim 8473, wherein the first,second, and third volumes comprise rectangular footprints.
 8488. Themethod of claim 8473, wherein the first, second, and third volumescomprise square footprints.
 8489. The method of claim 8473, wherein thefirst, second, and third volumes comprise circular footprints.
 8490. Themethod of claim 8473, wherein the first, second, and third volumescomprise footprints in a concentric ring pattern.
 8491. The method ofclaim 8473, further comprising maintaining a temperature in at least aportion of the formation in a pyrolysis temperature range with a lowerpyrolysis temperature of about 250° C. and an upper pyrolysistemperature of about 400° C.
 8492. The method of claim 8473, furthercomprising pyrolyzing at least some of the hydrocarbons in theformation.
 8493. The method of claim 8473, further comprisingcontrolling a pressure and a temperature in at least a majority of thepart of the formation, wherein the pressure is controlled as a functionof temperature, or the temperature is controlled as a function ofpressure.
 8494. The method of claim 8473, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 8495. The method of claim 8473, further comprisingcontrolling a pressure in at least a majority of a part of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 8496. The method of claim 8473, further comprising controllingformation conditions such that the produced mixture comprises a partialpressure of H₂ in the mixture greater than about 0.5 bars.
 8497. Themethod of claim 8473, wherein the third set of heaters begins heatingwithin 6 months before or after the first set or second set of heatersbegin heating.
 8498. A method for treating a hydrocarbon containingformation, comprising: heating a first volume of the formation using afirst set of heaters; and heating a second volume of the formation usinga second set of heaters, wherein the first volume is spaced apart fromthe second volume by a third volume of the formation, and wherein thefirst volume, second volume, and third volume are sized, shaped, orlocated to inhibit deformation of subsurface equipment caused bygeomechanical motion of the formation during heating.
 8499. The methodof claim 8498, further comprising allowing the heat to transfer from thefirst and second volumes of the formation to at least a part of theformation.
 8500. The method of claim 8498, wherein a footprint of thefirst volume, second volume, or third volume is sized, shaped, orlocated to inhibit deformation of subsurface equipment caused bygeomechanical motion of the formation during heating.
 8501. The methodof claim 8498, further comprising producing a mixture from theformation.
 8502. The method of claim 8498, further comprising sizing,shaping, or locating the first volume, second volume, or third volume toinhibit deformation of subsurface equipment caused by geomechanicalmotion of the formation during heating.
 8503. The method of claim 8498,further comprising calculating geomechanical motion in a footprint ofthe first volume or the second volume, and using the calculatedgeomechanical motion to size, shape, or locate the first volume, thesecond volume, or the third volume.
 8504. The method of claim 8498,further comprising allowing the heat to transfer from the first andsecond volumes of the formation to at least a part of the formation, andproducing a mixture from the formation.
 8505. The method of claim 8498,wherein the third volume substantially surrounds the first volume, andthe second volume substantially surrounds the first volume.
 8506. Themethod of claim 8498, wherein the third volume substantially surroundsall or a portion of the first volume, and the second volumesubstantially surrounds all or a portion of the third volume.
 8507. Themethod of claims 8498, wherein the third volume has a footprint that isa linear, curved, or irregular shaped strip.
 8508. The method of claim8498, wherein the first and second volumes comprise rectangularfootprints.
 8509. The method of claim 8498, wherein the first and secondvolumes comprise square footprints.
 8510. The method of claim 8498,wherein the first and second volumes comprise circular footprints. 8511.The method of claim 8498, wherein the first and second volumes comprisefootprints in a concentric ring pattern.
 8512. The method of claim 8498,wherein the first, second, and third volumes comprise rectangularfootprints.
 8513. The method of claim 8498, wherein the first, second,and third volumes comprise square footprints.
 8514. The method of claim8498, wherein the first, second, and third volumes comprise circularfootprints.
 8515. The method of claim 8498, wherein the first, second,and third volumes comprise footprints in a concentric ring pattern.8516. The method of claim 8498, wherein the first, second, or thirdvolumes are sized, shaped, or located based on, at least in part, acalculated geomechanical motion of at least a portion of the formation.8517. The method of claim 8498, further comprising sizing, shaping, orlocating the first, second, or third volumes based on, at least in part,a calculated geomechanical motion of at least a portion of theformation.
 8518. The method of claim 8498, wherein the first, second, orthird volumes are sized, shaped, or located, at least in part, toinhibit deformation, caused by geomechanical motion, of one or moreselected wellbores in the formation.
 8519. The method of claim 8498,wherein the first, second, or third volumes are at least in part sized,shaped, or located based on a calculated geomechanical motion of atleast a portion of the formation, and wherein the first, second, orthird volumes are sized, shaped, or located, at least in part, toinhibit deformation, caused by geomechanical motion, of one or moreselected wellbores in the formation.
 8520. The method of claim 8498,wherein the first, second, or third volumes of the formation have beensized, shaped, or located, at least in part, based on a simulation.8521. The method of claim 8498, wherein the first, second, and thirdvolumes of the formation have been sized, shaped, or located, at leastin part, based on a simulation.
 8522. The method of claim 8498, whereina footprint area of the first volume, second volume, or third volume isless than about 400 square meters.
 8523. The method of claim 8498,wherein the third set of heaters begin heating after a selected amountof geomechanical motion in the first or second volumes.
 8524. The methodof claim 8498, wherein the third set of heaters begin heating tomaintain or enhance a production rate of the mixture from the formation.8525. The method of claim 8498, wherein the selected time has been atleast in part determined using a simulation.
 8526. The method of claim8498, further comprising maintaining a temperature in at least a portionof the formation in a pyrolysis temperature range with a lower pyrolysistemperature of about 250° C. and an upper pyrolysis temperature of about400° C.
 8527. The method of claim 8498, further comprising pyrolyzing atleast some of the hydrocarbons in the formation.
 8528. The method ofclaim 8498, further comprising controlling a pressure and a temperaturein at least a part of the formation, wherein the pressure is controlledas a function of temperature, or the temperature is controlled as afunction of pressure.
 8529. The method of claim 8498, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8530. The method of claim 8498, furthercomprising controlling a pressure in at least a part of the formation,wherein the controlled pressure is at least about 2.0 bars absolute.8531. The method of claim 8498, further comprising controlling formationconditions such that the produced mixture comprises a partial pressureof H₂ in the mixture greater than about 0.5 bars.
 8532. A systemconfigured to heat at least a part of a hydrocarbon containingformation, comprising: one or more electrical conductors configured tobe placed in an opening in the formation, wherein at least oneelectrical conductor comprises at least one electrically resistiveportion configured to provide a heat output when current is appliedthrough such electrically resistive portion, and wherein at least one ofsuch electrically resistive portions is configured, when above or near aselected temperature, to automatically provide a reduced heat output;and wherein the system is configured to allow heat to transfer from atleast one of the electrically resistive portions to at least a part ofthe formation.
 8533. The system of claim 8532, wherein at least oneelectrical conductor is configured to propagate electrical current outof the opening.
 8534. The system of claim 8532, wherein at least oneelectrical conductor is configured to propagate electrical current intothe opening.
 8535. The system of claim 8532, wherein the system isconfigured to pyrolyze at least some hydrocarbons in the formation.8536. The system of claim 8532, wherein three or more electricalconductors are configured to be coupled in a three-phase electricalconfiguration.
 8537. The system of claim 8532, wherein at least oneelectrical conductor comprises an inner conductor and at least oneelectrical conductor comprises an outer conductor.
 8538. The system ofclaim 8532, further comprising an electrically insulating materialplaced between at least two electrical conductors.
 8539. The system ofclaim 8532, further comprising an electrically insulating material,comprising a packed powder, placed between at least two electricalconductors.
 8540. The system of claim 8532, further comprising aflexible electrically insulating material placed between at least twoelectrical conductors.
 8541. The system of claim 8532, wherein at leastone electrically resistive portion comprises a resistance that decreasesat, near, or above the selected temperature such that the at least oneelectrically resistive portion provides a reduced heat output above theselected temperature.
 8542. The system of claim 8532, wherein at leastone electrically resistive portion comprises a ferromagnetic material.8543. The system of claim 8532, wherein at least one electricallyresistive portion comprises a ferromagnetic material comprising iron,nickel, chromium, cobalt, or mixtures thereof.
 8544. The system of claim8532, wherein at least one electrically resistive portion comprises aferromagnetic material with sufficient thickness that is substantiallygreater than the skin depth at the Curie temperature of theferromagnetic material.
 8545. The system of claim 8532, wherein at leastone electrically resistive portion comprises a ferromagnetic materialwith sufficient thickness such that the thickness is substantiallygreater than the skin depth at the Curie temperature of theferromagnetic material, and wherein the ferromagnetic material iscoupled to a more conductive material such that, at the Curietemperature of the ferromagnetic material, the electrically resistiveportion has a higher conductivity than the electrically resistiveportion would if the ferromagnetic material were used, in the same orgreater thickness, without the more conductive material.
 8546. Thesystem of claim 8532, wherein at least one electrically resistiveportion comprises a first ferromagnetic material with a first Curietemperature, and a second ferromagnetic material with a second Curietemperature.
 8547. The system of claim 8532, wherein at least oneelectrically resistive portion comprises a ferromagnetic material with athickness greater than the skin depth of the ferromagnetic material atthe Curie temperature of the ferromagnetic material.
 8548. The system ofclaim 8532, wherein at least one electrically resistive portioncomprises ferromagnetic material with a thickness at least about 1.5times greater than the skin depth of the ferromagnetic material at theCurie temperature of the ferromagnetic material.
 8549. The system ofclaim 8532, wherein at least one electrically resistive portioncomprises ferromagnetic material coupled to a higher conductivitymaterial.
 8550. The system of claim 8532, wherein at least oneelectrically resistive portion comprises ferromagnetic material coupledto a higher conductivity non-ferromagnetic material.
 8551. The system ofclaim 8532, wherein at least one electrically resistive portioncomprises ferromagnetic material, and wherein the selected temperatureis approximately the Curie temperature of the ferromagnetic material.8552. The system of claim 8532, wherein at least one electricallyresistive portion comprises ferromagnetic material and non-ferromagneticelectrically conductive material.
 8553. The system of claim 8532,wherein at least one electrically conductive portion is locatedproximate a relatively rich zone of the formation.
 8554. The system ofclaim 8532, wherein at least one electrically resistive portion islocated proximate a hot spot of the formation.
 8555. The system of claim8532, wherein at least one electrically resistive portion comprisescarbon steel.
 8556. The system of claim 8532, wherein at least oneelectrically resistive portion comprises iron.
 8557. The system of claim8532, wherein the electrically resistive portion comprises aferromagnetic material, and the ferromagnetic material is coupled to acorrosion resistant material.
 8558. The system of claim 8532, whereinthe electrically resistive portion comprises a ferromagnetic material,and a corrosion resistant material is coated on the ferromagneticmaterial.
 8559. The system of claim 8532, wherein the electricallyresistive portion comprises one or more bends.
 8560. The system of claim8532, wherein the electrically resistive portion comprises a helicallyshaped portion.
 8561. The system of claim 8532, wherein the electricallyresistive portion is part of an insulated conductor.
 8562. The system ofclaim 8532, wherein the electrically resistive portion comprises athickness of ferromagnetic material, and such ferromagnetic material iscoupled to a thickness of a more conductive material, and wherein thethickness of the ferromagnetic material and the thickness of the moreconductive material have been selected such that the electricallyresistive portion provides a selected resistance profile as a functionof temperature.
 8563. The system of claim 8532, wherein the electricallyresistive portion comprises a thickness of a ferromagnetic material, andsuch ferromagnetic material comprises iron, nickel, chromium, cobalt, ormixtures thereof, and such ferromagnetic material is coupled to athickness of a more conductive material, and wherein the thickness ofthe ferromagnetic material and the thickness of the more conductivematerial have been selected such that the electrically resistive portionprovides a selected resistance profile as a function of temperature.8564. The system of claim 8532, wherein the electrically resistiveportion comprises a thickness of a ferromagnetic material, and suchferromagnetic material comprises a first Curie temperature material anda second Curie temperature material, and such ferromagnetic material iscoupled to a thickness of a more conductive material, and wherein thethickness of the ferromagnetic material and the thickness of the moreconductive material have been selected such that the electricallyresistive portion provides a selected resistance profile as a functionof temperature.
 8565. The system of claim 8532, wherein the electricallyresistive portion comprises a thickness of a ferromagnetic material, andsuch ferromagnetic material is coupled to a thickness of a moreconductive material, and wherein the thickness and skin depthcharacteristics of the ferromagnetic material, and the thickness of themore conductive material, have been selected such that the electricallyresistive portion provides a selected resistance profile as a functionof temperature.
 8566. The system of claim 8532, wherein the electricallyresistive portion is part of an insulated conductor, and wherein theinsulated conductor comprises a lead-in conductor and a lead-outconductor.
 8567. The system of claim 8532, wherein the electricallyresistive portion is part of an insulated conductor, and wherein theinsulated conductor is coupled to a support member.
 8568. The system ofclaim 8532, wherein the electrically resistive portion is part of aninsulated conductor, and the insulated conductor is frictionally securedagainst a cased or open wellbore.
 8569. The system of claim 8532,wherein the electrically resistive portion is part of aconductor-in-conduit.
 8570. The system of claim 8532, wherein at leastone electrical conductor is electrically coupled to the earth, andwherein electrical current is propagated from the electrical conductorto the earth.
 8571. The system of claim 8532, wherein the reduced heatoutput is less than about 800 watts per meter.
 8572. The system of claim8532, wherein at least one electrical conductor comprises at least onesection configured to comprise a relatively flat resistance profile in atemperature range between about 100° C. and 750° C.
 8573. The system ofclaim 8532, wherein at least one electrical conductor comprises at leastone section configured to comprise a relatively flat resistance profilein a temperature range between about 100° C. and 750° C., and arelatively sharp resistance profile at a temperature above about 750° C.and less than about 850° C.
 8574. The system of claim 8532, wherein atleast one electrical conductor comprises at least one section configuredto comprise a relatively flat resistance profile in a temperature rangebetween about 300° C. and 600° C.
 8575. The system of claim 8532,wherein the at least one electrical conductor is greater than about 10 min length.
 8576. The system of claim 8532, wherein the at least oneelectrical conductor is greater than about 50 m in length.
 8577. Thesystem of claim 8532, wherein the at least one electrical conductor isgreater than about 100 m in length.
 8578. The system of claim 8532,wherein the system is configured to reduce heat output such that thesystem does not overheat in the opening.
 8579. The system of claim 8532,wherein the system is configured to sharply reduce heat output at ornear the selected temperature.
 8580. The system of claim 8532, whereinthe electrically resistive portion comprises drawn iron.
 8581. Thesystem of claim 8532, wherein the electrically resistive portioncomprises a ferromagnetic material drawn together or against a moreconductive material.
 8582. The system of claim 8532, wherein theelectrically resistive portion comprises an elongated conduit comprisingiron, wherein a center of the conduit is lined or filled with a materialcomprising copper or aluminum.
 8583. The system of claim 8532, whereinthe electrically resistive portion comprises an elongated conduitcomprising iron, wherein a center of the conduit is lined or filled witha material comprising copper or aluminum, and wherein the copper oraluminum was melted in a center of the conduit and allowed to harden.8584. The system of claim 8532, wherein the electrically resistiveportion comprises an elongated conduit comprising a center portion andan outer portion, and wherein the diameter of the center portion is atleast about 0.5 cm and comprises iron.
 8585. The system of claim 8532,wherein the electrically resistive portion comprises an elongatedconduit comprising a center portion and an outer portion.
 8586. Thesystem of claim 8532, wherein the electrically resistive portioncomprises an elongated conduit comprising a center portion and an outerportion, and wherein the diameter of the center portion is at leasttwice the skin depth.
 8587. The system of claim 8532, wherein thecurrent is an alternating current.
 8588. The system of claim 8532,wherein at least one of the electrically resistive portions comprises acomposite material, wherein the composite material comprises a firstmaterial that has a resistance that declines when heated to the selectedtemperature, and wherein the composite material includes a secondmaterial that is more electrically conductive than the first material,and wherein the first material is coupled to the second material. 8589.The system of claim 8532, wherein the system is configured such that, ator near the selected temperature, the heat output of at least a portionof the system declines due to the Curie effect.
 8590. The system ofclaim 8532, wherein the heat output is reduced below the rate at whichthe formation will absorb or transfer heat, thereby inhibitingoverheating of the formation.
 8591. The system of claim 8532, whereinthe electrically resistive portion comprises a magnetic material that,at or near the selected temperature, becomes substantially nonmagnetic.8592. The system of claim 8532, wherein the electrically resistiveportion is elongated, and configured such that only portions of theelectrically resistive portion that are at or near the selectedtemperature will automatically reduce heat output.
 8593. The system ofclaim 8532, wherein the system comprises a heater which in turncomprises one or more of the electrically resistive portions.
 8594. Thesystem of claim 8532, configured such that when a temperature of atleast one electrically resistive portion is below the selectedtemperature, and such temperature increases, then the resistance of suchelectrically resistive portion increases.
 8595. The system of claim8532, configured such that when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion decreases.
 8596. The system of claim 8532, configuredthat when a temperature of at least one electrically resistive portionis below the selected temperature, and such temperature increases, thenthe resistance of such electrically resistive portion graduallydecreases.
 8597. The system of claim 8532, configured such that when atemperature of at least one electrically resistive portion is above theselected temperature, and such temperature increases, then theresistance of such electrically resistive portion sharply decreases.8598. The system of claim 8532, configured such that when a temperatureof at least one electrically resistive portion is below the selectedtemperature, and such temperature increases, then the resistance of suchelectrically resistive portion increases, and when a temperature of atleast one electrically resistive portion is above the selectedtemperature, and such temperature increases, then the resistance of suchelectrically resistive portion decreases.
 8599. The system of claim8532, configured such that when a temperature of at least oneelectrically resistive portion is below the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion increases, and when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion decreases, and wherein the selected temperature is atemperature above the boiling point of water but below a failuretemperature of one or more system components.
 8600. The system of claim8532, configured such that when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion gradually decreases.
 8601. The system of claim 8532,configured such that different portions of the formation, with differentthermal conductivities, can be heated within 10% of the failuretemperature of the system.
 8602. A method for heating a hydrocarboncontaining formation, comprising: applying an electrical current to oneor more electrical conductors placed in an opening in the formation,wherein at least one electrical conductor comprises one or moreelectrically resistive portions configured to provide a heat output whenelectrical current is applied through such electrically resistiveportion, and wherein at least one of such electrically resistiveportions is configured, when above or near a selected temperature, toautomatically provide a reduced heat output; and allowing the heat totransfer from one or more electrical resistive portions to at least apart of the formation.
 8603. The method of claim 8602, furthercomprising applying a relatively constant electrical current to the oneor more electrical conductors.
 8604. The method of claim 8602, furthercomprising providing electrical current to one or more electricalconductors.
 8605. The method of claim 8602, further comprising providinga relatively constant heat output in a temperature range between about300° C. and 600° C.
 8606. The method of claim 8602, further comprisingproviding a relatively constant heat output in a temperature rangebetween about 100° C. and 750° C.
 8607. The method of claim 8602,wherein at least one electrically conductive portion comprises aresistance that decreases above the selected temperature such that theelectrically conductive portion provides the reduced heat output abovethe selected temperature.
 8608. The method of claim 8602, wherein atleast one electrically conductive portion comprises ferromagneticmaterial with a thickness at least 1.5 times greater than the skin depthof the ferromagnetic material at the Curie temperature of theferromagnetic material.
 8609. The method of claim 8602, wherein at leastone electrically conductive portion comprises ferromagnetic material.8610. The method of claim 8602, further comprising locating at least oneelectrically resistive portion proximate a relatively rich zone of theformation.
 8611. The method of claim 8602, further comprising locatingat least one electrically resistive portion proximate a hot spot of theformation.
 8612. The method of claim 8602, further comprising pyrolyzingat least some hydrocarbons within the formation.
 8613. The method ofclaim 8602, further comprising controlling a pressure and a temperaturewithin at least a part of the formation, wherein the pressure iscontrolled as a function of temperature, and/or the temperature iscontrolled as a function of pressure.
 8614. The method of claim 8602,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8615. The method of claim 8602, furthercomprising controlling a pressure within at least a part of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 8616. The method of claim 8602, further comprising controllingformation conditions such that a produced mixture comprises a partialpressure of H₂ within the mixture greater than about 0.5 bars.
 8617. Themethod of claim 8602, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 8618. The method of claim8602, wherein at least a portion of the part of the formation is heatedto a minimum pyrolysis temperature of about 270° C.
 8619. The method ofclaim 8602, wherein the reduced heat output is less than about 800 wattsper meter.
 8620. The method of claim 8602, further comprisingcontrolling a skin depth in at least one electrically resistive portionby controlling a frequency of alternating current applied to at leastone electrically resistive portion.
 8621. The method of claim 8602,further comprising applying additional power to at least oneelectrically resistive portion as the temperature of the electricallyresistive portion increases, and continuing to do so until thetemperature is at or near the selected temperature.
 8622. The method ofclaim 8602, wherein the hydrocarbon containing formation contains atleast two portions with different thermal conductivities, and furthercomprising applying heat to such portions with an electrically resistiveportion that is proximate to such portions, and further comprisingautomatically allowing less heat to be applied from a part of anelectrically resistive portion that is proximate a portion of theformation with a lower thermal conductivity.
 8623. The method of claim8602, wherein the hydrocarbon containing formation contains at least twoportions with different thermal conductivities, and further comprisingapplying heat to such portions with an electrically resistive portionthat is proximate to such portions, and further comprising automaticallyallowing less heat to be applied from a part of the electricallyresistive portion that is proximate a portion of the formation with alower thermal conductivity while also allowing more heat to be appliedfrom a part of the electrically resistive portion that is proximate aportion of the formation with a higher thermal conductivity.
 8624. Themethod of claim 8602, wherein the hydrocarbon containing formationcontains at least two layers with different thermal conductivities, andfurther comprising applying heat to such layers with an electricallyresistive portion that is proximate to such layers, and furthercomprising automatically allowing less heat to be applied from a part ofan electrically resistive portion that is proximate a layer of theformation with a lower thermal conductivity.
 8625. The method of claim8602, wherein the hydrocarbon containing formation contains at least twolayers with different thermal conductivities, and further comprisingapplying heat to such layers with an electrically resistive portion thatis proximate to such layers, and further comprising automaticallyallowing less heat to be applied from a part of the electricallyresistive portion that is proximate a layer of the formation with alower thermal conductivity while also allowing more heat to be appliedfrom a part of the electrically resistive portion that is proximate alayer of the formation with a higher thermal conductivity.
 8626. Themethod of claim 8602, further comprising controlling the heat appliedfrom an electrically resistive portion by allowing less heat to beapplied from any part of the electrically resistive portion that is ator near the selected temperature.
 8627. The method of claim 8602,wherein the hydrocarbon containing formation comprises an oil shaleformation.
 8628. The method of claim 8602, wherein the hydrocarboncontaining formation comprises a coal formation.
 8629. The method ofclaim 8602, wherein the hydrocarbon containing formation comprises a tarsands formation.
 8630. A system configured to heat at least a part of ahydrocarbon containing formation, comprising: one or more electricalconductors configured to be placed in an opening in the formation,wherein at least one electrical conductor comprises a ferromagneticmaterial configured to provide a reduced heat output above or near aselected temperature; and wherein the system is configured to allow heatto transfer from the electrical conductors to a part of the formation.8631. The system of claim 8630, wherein at least one electricalconductor is configured to propagate electrical current into theopening.
 8632. The system of claim 8630, wherein the system isconfigured to pyrolyze at least some hydrocarbons in the formation.8633. The system of claim 8630, wherein at least one electricalconductor is configured to propagate electrical current out of theopening.
 8634. The system of claim 8630, wherein three or moreelectrical conductors are configured to be coupled in a three-phaseelectrical configuration.
 8635. The system of claim 8630, wherein atleast one electrical conductor comprises an inner conductor and at leastone electrical conductor comprises an outer conductor.
 8636. The systemof claim 8630, further comprising an electrically insulating materialplaced between at least two electrical conductors.
 8637. The system ofclaim 8630, further comprising a flexible electrically insulatingmaterial placed between at least two electrical conductors.
 8638. Thesystem of claim 8630, wherein the ferromagnetic material comprises aresistance that decreases above the selected temperature such that thesystem provides the reduced heat output above the selected temperature.8639. The system of claim 8630, wherein the ferromagnetic materialcomprises a thickness greater than the skin depth of the ferromagneticmaterial at the Curie temperature of the ferromagnetic material. 8640.The system of claim 8630, wherein the ferromagnetic material comprises athickness at least 1.5 times greater than the skin depth of theferromagnetic material at the Curie temperature of the ferromagneticmaterial.
 8641. The system of claim 8630, further comprising a higherconductivity material coupled to the ferromagnetic material.
 8642. Thesystem of claim 8630, further comprising a higher conductivitynon-ferromagnetic material coupled to the ferromagnetic material. 8643.The system of claim 8630, further comprising a second ferromagneticmaterial coupled to the ferromagnetic material.
 8644. The system ofclaim 8630, wherein the selected temperature is approximately the Curietemperature of the ferromagnetic material.
 8645. The system of claim8630, wherein at least one electrical conductor comprises ferromagneticmaterial and non-ferromagnetic, electrically conductive material. 8646.The system of claim 8630, wherein the ferromagnetic material comprisesiron.
 8647. The system of claim 8630, wherein at least one electricalconductor is electrically coupled to the earth, and wherein electricalcurrent is propagated from the electrical conductor to the earth. 8648.The system of claim 8630, wherein the reduced heat output is less thanabout 800 watts per meter.
 8649. The system of claim 8630, wherein atleast one electrical conductor comprises at least one section configuredto comprise a relatively flat resistance profile in a temperature rangebetween about 100° C. and 750° C.
 8650. The system of claim 8630,wherein the at least one electrical conductor is greater than about 10 min length.
 8651. A method for heating a hydrocarbon containingformation, comprising: applying an electrical current to one or moreelectrical conductors placed in an opening in the formation, wherein atleast one electrical conductor comprises a ferromagnetic materialconfigured to provide a reduced heat output above or near a selectedtemperature; and allowing the heat to transfer from the one or moreelectrical conductors to a part of the formation.
 8652. The method ofclaim 8651, further comprising applying a relatively constant electricalcurrent to the one or more electrical conductors.
 8653. The method ofclaim 8651, further comprising allowing the electrical current topropagate through at least one electrical conductor into the opening.8654. The method of claim 8651, further comprising providing arelatively constant heat output in a temperature range between about100° C. and 750° C.
 8655. The method of claim 8651, wherein theferromagnetic material comprises a resistance that decreases above theselected temperature such that the ferromagnetic material provides thereduced heat output above the selected temperature.
 8656. The method ofclaim 8651, wherein the ferromagnetic material comprises a thickness atleast 1.5 times greater than the skin depth of the ferromagneticmaterial at the Curie temperature of the ferromagnetic material. 8657.The method of claim 8651, wherein the selected temperature isapproximately the Curie temperature of the ferromagnetic material. 8658.The method of claim 8651, further comprising pyrolyzing at least somehydrocarbons within the formation.
 8659. The method of claim 8651,further comprising controlling a pressure and a temperature within atleast a part of the formation, wherein the pressure is controlled as afunction of temperature, and/or the temperature is controlled as afunction of pressure.
 8660. The method of claim 8651, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 8661. The method of claim 8651, further comprisingcontrolling a pressure within at least a part of the formation, whereinthe controlled pressure is at least about 2.0 bars absolute.
 8662. Themethod of claim 8651, further comprising controlling formationconditions such that a produced mixture comprises a partial pressure ofH₂ within the mixture greater than about 0.5 bars.
 8663. The method ofclaim 8651, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 8664. The method of claim 8651, whereinat least a portion of the part of the formation is heated to a minimumpyrolysis temperature of about 270° C.
 8665. The method of claim 8651,wherein the reduced heat output is less than about 800 watts per meter.8666. The method of claim 8651, wherein the hydrocarbon containingformation comprises an oil shale formation.
 8667. The method of claim8651, wherein the hydrocarbon containing formation comprises a coalformation.
 8668. The method of claim 8651, wherein the hydrocarboncontaining formation comprises a tar sands formation.
 8669. A systemconfigured to heat at least a part of a hydrocarbon containingformation, comprising: one or more electrical conductors configured tobe placed in an opening in the formation, wherein at least oneelectrical conductor comprises a ferromagnetic material configured toprovide a reduced heat output above or near a selected temperature,wherein at least one electrical conductor is electrically coupled to theearth, and wherein electrical current is propagated from the electricalconductor to the earth; and wherein the system is configured to allowheat to transfer from the electrical conductors to a part of theformation.
 8670. The system of claim 8669, wherein at least oneelectrical conductor is electrically coupled to the earth through anelectrical contacting section.
 8671. The system of claim 8669, whereinthe electrical contacting section comprises a second opening coupled tothe opening.
 8672. The system of claim 8669, wherein the electricalcontacting section comprises a second opening coupled to the opening andhaving a larger diameter than the opening.
 8673. The system of claim8669, wherein the electrical contacting section comprises a secondopening coupled to the opening, and wherein the second opening is filledwith a material that enhances electrical contact between at least oneelectrical conductor and the earth.
 8674. The system of claim 8669,wherein at least one electrical conductor is configured to propagateelectrical current into the opening.
 8675. The system of claim 8669,wherein at least one electrical conductor is configured to propagateelectrical current out of the opening.
 8676. The system of claim 8669,wherein three or more electrical conductors are configured to be coupledin a three-phase electrical configuration.
 8677. The system of claim8669, wherein at least one electrical conductor comprises an innerconductor and at least one electrical conductor comprises an outerconductor.
 8678. The system of claim 8669, further comprising anelectrically insulating material placed between at least two electricalconductors.
 8679. The system of claim 8669, further comprising aflexible electrically insulating material placed between at least twoelectrical conductors.
 8680. The system of claim 8669, wherein theferromagnetic material comprises a resistance that decreases above theselected temperature such that the system provides the reduced heatoutput above the selected temperature.
 8681. The system of claim 8669,wherein the ferromagnetic material comprises a thickness greater thanthe skin depth of the ferromagnetic material at the Curie temperature ofthe ferromagnetic material.
 8682. The system of claim 8669, wherein theferromagnetic material comprises a thickness at least 1.5 times greaterthan the skin depth of the ferromagnetic material at the Curietemperature of the ferromagnetic material.
 8683. The system of claim8669, further comprising a higher conductivity material coupled to theferromagnetic material.
 8684. The system of claim 8669, furthercomprising a higher conductivity non-ferromagnetic material coupled tothe ferromagnetic material.
 8685. The system of claim 8669, furthercomprising a second ferromagnetic material coupled to the ferromagneticmaterial.
 8686. The system of claim 8669, wherein the selectedtemperature is approximately the Curie temperature of the ferromagneticmaterial.
 8687. The system of claim 8669, wherein at least oneelectrical conductor comprises ferromagnetic material andnon-ferromagnetic, electrically conductive material.
 8688. The system ofclaim 8669, wherein the ferromagnetic material comprises iron.
 8689. Thesystem of claim 8669, wherein the reduced heat output is less than about800 watts per meter.
 8690. The system of claim 8669, wherein at leastone electrical conductor comprises at least one section configured tocomprise a relatively flat resistance profile in a temperature rangebetween about 100° C. and 750° C.
 8691. The system of claim 8669,wherein the at least one electrical conductor is greater than about 10 min length.
 8692. The system of claim 8669, wherein the system isconfigured for use in soil remediation of the hydrocarbon containingformation.
 8693. The system of claim 8669, configured such thatdifferent portions of the formation, with different thermalconductivities, can be heated within 10% of the failure temperature ofthe system.
 8694. A method for heating a hydrocarbon containingformation, comprising: applying an electrical current to one or moreelectrical conductors placed in an opening in the formation, wherein atleast one electrical conductor comprises a ferromagnetic materialconfigured to provide a reduced heat output above or near a selectedtemperature, wherein at least one electrical conductor is electricallycoupled to the earth, and wherein electrical current is propagated fromthe electrical conductor to the earth; and allowing the heat to transferfrom the one or more electrical conductors to a part of the formation.8695. The method of claim 8694, further comprising applying a relativelyconstant electrical current to the one or more electrical conductors.8696. The method of claim 8694, further comprising allowing theelectrical current to propagate through at least one electricalconductor into the opening.
 8697. The method of claim 8694, furthercomprising providing a relatively constant heat output in a temperaturerange between about 100° C. and 750° C.
 8698. The method of claim 8694,wherein the ferromagnetic material comprises a resistance that decreasesabove the selected temperature such that the ferromagnetic materialprovides the reduced heat output above the selected temperature. 8699.The method of claim 8694, wherein the ferromagnetic material comprises athickness at least 1.5 times greater than the skin depth of theferromagnetic material at the Curie temperature of the ferromagneticmaterial.
 8700. The method of claim 8694, wherein the selectedtemperature is approximately the Curie temperature of the ferromagneticmaterial.
 8701. The method of claim 8694, further comprising pyrolyzingat least some hydrocarbons within the formation.
 8702. The method ofclaim 8694, further comprising controlling a pressure and a temperaturewithin at least a part of the formation, wherein the pressure iscontrolled as a function of temperature, and/or the temperature iscontrolled as a function of pressure.
 8703. The method of claim 8694,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8704. The method of claim 8694, furthercomprising controlling a pressure within at least a part of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 8705. The method of claim 8694, further comprising controllingformation conditions such that a produced mixture comprises a partialpressure of H₂ within the mixture greater than about 0.5 bars.
 8706. Themethod of claim 8694, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 8707. The method of claim8694, wherein at least a portion of the part of the formation is heatedto a minimum pyrolysis temperature of about 270° C.
 8708. The method ofclaim 8694, wherein the reduced heat output is less than about 800 wattsper meter.
 8709. A heater, comprising: an electrical conductorconfigured to generate heat during application of electrical current tothe electrical conductor; and wherein the electrical conductor comprisesa ferromagnetic material having a thickness greater than the skin depthof the ferromagnetic material at the Curie temperature of theferromagnetic material such that the heater provides a reduced heatoutput above or near a selected temperature.
 8710. The heater of claim8709, wherein the heater is configured to allow heat to transfer fromthe heater to a part of a hydrocarbon containing formation to pyrolyzeat least some hydrocarbons in the hydrocarbon containing formation.8711. The heater of claim 8709, wherein the heater is configured to beplaced in an opening in a hydrocarbon containing formation.
 8712. Theheater of claim 8709, wherein the heater is configured to be placed inan opening in an oil shale formation.
 8713. The heater of claim 8709,wherein the heater is configured to be placed in an opening in a coalformation.
 8714. The heater of claim 8709, wherein the heater isconfigured to be placed in an opening in a tar sands formation. 8715.The heater of claim 8709, further comprising two additional electricalconductors configured to generate heat during application of electricalcurrent to the two additional electrical conductors, wherein theelectrical conductor and the two additional electrical conductors areconfigured to be coupled in a three-phase electrical configuration.8716. The heater of claim 8709, further comprising at least oneadditional electrical conductor.
 8717. The heater of claim 8709, furthercomprising at least one additional electrical conductor and anelectrically insulating material placed between the electrical conductorand at least one additional electrical conductor.
 8718. The heater ofclaim 8709, further comprising at least one additional electricalconductor and a flexible electrically insulating material placed betweenthe electrical conductor and at least one additional electricalconductor.
 8719. The heater of claim 8709, wherein a resistance of theferromagnetic material decreases above the selected temperature suchthat the heater provides the reduced heat output above the selectedtemperature.
 8720. The heater of claim 8709, wherein the ferromagneticmaterial comprises a thickness at least 1.5 times greater than the skindepth of the ferromagnetic material at the Curie temperature of theferromagnetic material.
 8721. The heater of claim 8709, furthercomprising a higher conductivity material coupled to the ferromagneticmaterial.
 8722. The heater of claim 8709, further comprising a higherconductivity non-ferromagnetic material coupled to the ferromagneticmaterial.
 8723. The heater of claim 8709, further comprising a secondferromagnetic material coupled to the ferromagnetic material.
 8724. Theheater of claim 8709, wherein the selected temperature is approximatelythe Curie temperature of the ferromagnetic material.
 8725. The heater ofclaim 8709, wherein the ferromagnetic material comprises iron.
 8726. Theheater of claim 8709, wherein the ferromagnetic material comprisescarbon steel.
 8727. The heater of claim 8709, wherein the reduced heatoutput is less than about 800 watts per meter.
 8728. The heater of claim8709, wherein the heater comprises a relatively flat resistance profilein a temperature range between about 100° C. and 750° C.
 8729. Theheater of claim 8709, wherein the heater is greater than about 10 m inlength.
 8730. A heating system, comprising: one or more electricalconductors, wherein at least one electrical conductor comprises at leastone electrically resistive portion configured to provide a heat outputwhen current is applied through such electrically resistive portion, andwherein at least one of such electrically resistive portions isconfigured, when above or near a selected temperature, to automaticallyprovide a reduced heat output.
 8731. The heating system of claim 8730,wherein three or more electrical conductors are configured to be coupledin a three-phase electrical configuration.
 8732. The heating system ofclaim 8730, wherein at least one electrical conductor comprises an innerconductor and at least one electrical conductor comprises an outerconductor.
 8733. The heating system of claim 8730, further comprising anelectrically insulating material placed between at least two electricalconductors.
 8734. The heating system of claim 8730, further comprisingan electrically insulating material, comprising a packed powder, placedbetween at least two electrical conductors.
 8735. The heating system ofclaim 8730, further comprising a flexible electrically insulatingmaterial placed between at least two electrical conductors.
 8736. Theheating system of claim 8730, wherein at least one electricallyresistive portion comprises a resistance that decreases above or nearthe selected temperature such that the at least one electricallyresistive portion provides a reduced heat output above the selectedtemperature.
 8737. The heating system of claim 8730, wherein at leastone electrically resistive portion comprises a ferromagnetic material.8738. The heating system of claim 8730, wherein at least oneelectrically resistive portion comprises a ferromagnetic material withsufficient thickness that is substantially greater than the skin depthat the Curie temperature of the ferromagnetic material.
 8739. Theheating system of claim 8730, wherein at least one electricallyresistive portion comprises a ferromagnetic material with sufficientthickness such that the thickness is substantially greater than the skindepth at the Curie temperature of the ferromagnetic material, andwherein the ferromagnetic material is coupled to a more conductivematerial such that, at the Curie temperature of the ferromagneticmaterial, the electrically resistive portion has a higher conductivitythan the electrically resistive portion would if the ferromagneticmaterial were used, in the same or greater thickness, without the moreconductive material.
 8740. The heating system of claim 8730, wherein atleast one electrically resistive portion comprises a first ferromagneticmaterial with a first Curie temperature, and a second ferromagneticmaterial with a second Curie temperature.
 8741. The heating system ofclaim 8730, wherein at least one electrically resistive portioncomprises a ferromagnetic material with a thickness greater than theskin depth of the ferromagnetic material at the Curie temperature of theferromagnetic material.
 8742. The heating system of claim 8730, whereinat least one electrically resistive portion comprises ferromagneticmaterial with a thickness at least about 1.5 times greater than the skindepth of the ferromagnetic material at the Curie temperature of theferromagnetic material.
 8743. The heating system of claim 8730, whereinat least one electrically resistive portion comprises ferromagneticmaterial coupled to a higher conductivity material.
 8744. The heatingsystem of claim 8730, wherein at least one electrically resistiveportion comprises ferromagnetic material coupled to a higherconductivity non-ferromagnetic material.
 8745. The heating system ofclaim 8730, wherein at least one electrically resistive portioncomprises ferromagnetic material, and wherein the selected temperatureis approximately the Curie temperature of the ferromagnetic material.8746. The heating system of claim 8730, wherein at least oneelectrically resistive portion comprises ferromagnetic material andnon-ferromagnetic, electrically conductive material.
 8747. The heatingsystem of claim 8730, wherein at least one electrically resistiveportion comprises carbon steel.
 8748. The heating system of claim 8730,wherein at least one electrically resistive portion comprises iron.8749. The heating system of claim 8730, wherein the electricallyresistive portion comprises a ferromagnetic material, and theferromagnetic material is coupled to a corrosion resistant material.8750. The heating system of claim 8730, wherein the electricallyresistive portion comprises a ferromagnetic material, and a corrosionresistant material that coated on the ferromagnetic material.
 8751. Theheating system of claim 8730, wherein the electrically resistive portioncomprises one or more bends.
 8752. The heating system of claim 8730,wherein the electrically resistive portion comprises a helically shapedportion.
 8753. The heating system of claim 8730, wherein theelectrically resistive portion is part of an insulated conductor. 8754.The heating system of claim 8730, wherein the electrically resistiveportion is part of an insulated conductor, and wherein the insulatedconductor is coupled to a support member.
 8755. The heating system ofclaim 8730, wherein the electrically resistive portion is part of aconductor-in-conduit.
 8756. The heating system of claim 8730, wherein atleast one electrical conductor is electrically coupled to the earth, andwherein electrical current is propagated from the electrical conductorto the earth.
 8757. The heating system of claim 8730, wherein thereduced heat output is less than about 800 watts per meter.
 8758. Theheating system of claim 8730, wherein at least one electrical conductorcomprises at least one section configured to comprise a relatively flatresistance profile in a temperature range between about 100° C. and 750°C.
 8759. The heating system of claim 8730, wherein at least oneelectrical conductor comprises at least one section configured tocomprise a relatively flat resistance profile in a temperature rangebetween about 100° C. and 750° C., and a relatively sharp resistanceprofile at a temperature above about 750° C. and less than about 850° C.8760. The heating system of claim 8730, wherein at least one electricalconductor comprises at least one section configured to comprise arelatively flat resistance profile in a temperature range between about300° C. and 600° C.
 8761. The heating system of claim 8730, wherein theat least one electrical conductor is greater than about 10 m in length.8762. The heating system of claim 8730, wherein the at least oneelectrical conductor is greater than about 50 m in length.
 8763. Theheating system of claim 8730, wherein the at least one electricalconductor is greater than about 100 m in length.
 8764. The heatingsystem of claim 8730, wherein the heating system is configured tosharply reduce heat output at or near the selected temperature. 8765.The heating system of claim 8730, wherein the electrically resistiveportion comprises drawn iron.
 8766. The heating system of claim 8730,wherein the electrically resistive portion comprises a ferromagneticmaterial drawn together or against a more conductive material.
 8767. Theheating system of claim 8730, wherein the electrically resistive portioncomprises an elongated conduit comprising iron, wherein a center of theconduit is lined or filled with a material comprising copper oraluminum.
 8768. The heating system of claim 8730, wherein theelectrically resistive portion comprises an elongated conduit comprisingiron, wherein a center of the conduit is lined or filled with a materialcomprising copper or aluminum, and wherein the copper or aluminum wasmelted in a center of the conduit and allowed to harden.
 8769. Theheating system of claim 8730, wherein the electrically resistive portioncomprises an elongated conduit comprising a center portion and an outerportion, and wherein the diameter of the center portion is at leastabout 0.5 cm and comprises iron.
 8770. The heating system of claim 8730,wherein the electrically resistive portion comprises an elongatedconduit comprising a center portion and an outer portion.
 8771. Theheating system of claim 8730, wherein the electrically resistive portioncomprises an elongated conduit comprising a center portion and an outerportion, and wherein the diameter of the center portion is at leasttwice the skin depth.
 8772. The heating system of claim 8730, whereinthe current is an alternating current.
 8773. The heating system of claim8730, wherein at least one of the electrically resistive portionscomprises a composite material, wherein the composite material comprisesa first material that has a resistance that declines when heated to theselected temperature, and wherein the composite material includes asecond material that is more electrically conductive than the firstmaterial, and wherein the first material is coupled to the secondmaterial.
 8774. The heating system of claim 8730, wherein the heatingsystem is configured such that, at or near the selected temperature, theheat output of at least a portion of the heating system declines due tothe Curie effect.
 8775. The heating system of claim 8730, wherein theelectrically resistive portion comprises a magnetic material that, at ornear the selected temperature, becomes substantially nonmagnetic. 8776.The heating system of claim 8730, wherein the electrically resistiveportion is elongated, and configured such that only portions of theelectrically resistive portion that are at or near the selectedtemperature will automatically reduce heat output.
 8777. The heatingsystem of claim 8730, configured such that when a temperature of atleast one electrically resistive portion is below the selectedtemperature, and such temperature increases, then the resistance of suchelectrically resistive portion increases.
 8778. The heating system ofclaim 8730, configured such that when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion decreases.
 8779. The heating system of claim 8730,configured that when a temperature of at least one electricallyresistive portion is above the selected temperature, and suchtemperature increases, then the resistance of such electricallyresistive portion gradually decreases.
 8780. The heating system of claim8730, configured such that when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion sharply decreases.
 8781. The heating system of claim8730, configured such that when a temperature of at least oneelectrically resistive portion is below the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion increases, and when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion decreases.
 8782. The heating system of claim 8730,configured such that when a temperature of at least one electricallyresistive portion is below the selected temperature, and suchtemperature increases, then the resistance of such electricallyresistive portion increases, and when a temperature of at least oneelectrically resistive portion is above the selected temperature, andsuch temperature increases, then the resistance of such electricallyresistive portion decreases, and wherein the selected temperature is atemperature above the boiling point of water but below a failuretemperature of one or more heating system components.
 8783. The heatingsystem of claim 8730, configured such that when a temperature of atleast one electrically resistive portion is above the selectedtemperature, and such temperature increases, then the resistance of suchelectrically resistive portion gradually decreases.
 8784. A method fortreating a hydrocarbon containing formation, comprising: inhibitingmigration of fluids into a first treatment area of the formation from asurrounding portion of the formation, wherein the first treatment areais surrounded, in whole or in part, by one or more openings, and whereinat least one opening comprises a first end that contacts a groundsurface at a first location, and a second end that contacts the groundsurface at a second location; heating at least a portion of the firsttreatment area with heaters to raise a temperature in the firsttreatment area above a pyrolysis temperature; and producing a mixturefrom the formation.
 8785. The method of claim 8784, further comprisingproviding a refrigerant to the one or more openings.
 8786. The method ofclaim 8784, wherein one or more of the openings comprises a firstconduit positioned in a second conduit.
 8787. The method of claim 8784,wherein at least one opening comprises a first conduit positioned in asecond conduit, the method further comprising flowing a refrigerantthrough the first conduit from the first end of one or more openingstowards a second end of one or more openings, and flowing an additionalrefrigerant through the second conduit from the second end of one ormore openings towards the first end of one or more openings.
 8788. Themethod of claim 8787, wherein the refrigerant flowing through the firstconduit flows countercurrently to the additional refrigerant flowingthrough the second conduit.
 8789. The method of claim 8787, wherein therefrigerant flowing through the first conduit flows cocurrently to theadditional refrigerant flowing through the second conduit.
 8790. Themethod of claim 8784, further comprising using at least one opening thatcontacts the ground surface at the first location and the secondlocation to form a substantially frozen subsurface barrier.
 8791. Themethod of claim 8784, further comprising forming at least one opening inthe formation with a river crossing rig.
 8792. The method of claim 8784,wherein the surrounding portion of the formation comprises at least aportion beside the first treatment area of the formation.
 8793. Themethod of claim 8784, wherein the surrounding portion of the formationcomprises at least a portion above the first treatment area of theformation.
 8794. The method of claim 8784, wherein the surroundingportion of the formation comprises at least a portion below the firsttreatment area of the formation.
 8795. The method of claim 8784, whereininhibiting migration of fluids comprises providing a barrier to at leasta portion of the formation.
 8796. The method of claim 8784, whereininhibiting migration of fluids comprises establishing a barrier in atleast a portion of the formation.
 8797. The method of claim 8784,further comprising controlling a pressure within the first treatmentarea.
 8798. The method of claim 8784, further comprising controlling atemperature within the first treatment area.
 8799. The method of claim8784, further comprising controlling a heating rate within the firsttreatment area.
 8800. The method of claim 8784, further comprisingcontrolling an amount of fluid removed from the first treatment area.8801. The method of claim 8784, further comprising establishing a lowtemperature barrier zone proximate to the first treatment area of theformation.
 8802. The method of claim 8784, further comprising using theopening to establish a frozen barrier zone to inhibit migration offluids into the first treatment area.
 8803. The method of claim 8784,further comprising establishing a frozen barrier zone to inhibitmigration of fluids out of the first treatment area.
 8804. The method ofclaim 8784, further comprising establishing a frozen barrier zone toinhibit migration of fluids into or out of the first treatment area,wherein the frozen barrier zone is proximate the first treatment area ofthe formation.
 8805. The method of claim 8784, further comprisingestablishing a frozen barrier zone to inhibit migration of fluids intoor out of the first treatment area, wherein at least one or more heatersis positioned greater than about 5 m from a frozen barrier zone. 8806.The method of claim 8784, further comprising establishing a frozenbarrier zone to inhibit migration of fluids into or out of the firsttreatment area, wherein at least one or more heaters is positioned lessthan about 1.5 m from a frozen barrier zone.
 8807. A method for treatinga hydrocarbon containing formation, comprising: forming one or moreopenings proximate to, or substantially surrounding, in whole or inpart, at least a portion of the formation, wherein at least one of theopenings comprises a first end that contacts a ground surface at a firstlocation, and a second end that contacts the ground surface at a secondlocation; forming a low temperature barrier zone using at least one ofthe openings that comprises a first end that contacts a ground surfaceat a first location, and a second end that contacts the ground surfaceat a second location; heating at least a portion of the formation topyrolyze at least some hydrocarbons in the formation; and producing amixture from the formation.
 8808. The method of claim 8807, furthercomprising providing a refrigerant to the one or more openings thatcomprise a first end that contacts a ground surface at a first location,and a second end that contacts the ground surface at a second location.8809. The method of claim 8807, wherein one or more of the openingscomprise a first conduit positioned in a second conduit.
 8810. Themethod of claim 8807, wherein at least one opening comprises a firstconduit positioned in a second conduit, the method further comprisingflowing a refrigerant through the first conduit from the first end ofone or more openings towards a second end of one or more openings, andflowing an additional refrigerant through the second conduit from thesecond end of one or more openings towards the first end of one or moreopenings.
 8811. The method of claim 8810, wherein the refrigerantflowing through the first conduit flows countercurrently to theadditional refrigerant flowing through the second conduit.
 8812. Themethod of claim 8810, wherein the refrigerant flowing through the firstconduit flows cocurrently to the additional refrigerant flowing throughthe second conduit.
 8813. The method of claim 8807, further comprisingforming at least one opening in the formation with a river crossing rig.8814. The method of claim 8807, wherein the low temperature barrier zoneis proximate to at least a portion of the formation being heated. 8815.The method of claim 8807, wherein the low temperature barrier zone isabove at least a portion of the formation being heated.
 8816. The methodof claim 8807, wherein the low temperature barrier zone is below atleast a portion of the formation being heated.
 8817. The method of claim8807, further comprising controlling a pressure in at least part of theformation being heated.
 8818. The method of claim 8807, furthercomprising controlling a temperature in at least part of the formationbeing heated.
 8819. The method of claim 8807, further comprisingcontrolling a heating rate in at least part of the formation beingheated.
 8820. The method of claim 8807, further comprising establishinga frozen barrier zone to inhibit migration of fluids in or out of theportion of the formation being heated.
 8821. The method of claim 8807,further comprising establishing a frozen barrier zone to inhibitmigration of fluids in or out of the portion of the formation beingheated, wherein the frozen barrier zone is proximate the portion of theformation being heated.
 8822. The method of claim 8807, furthercomprising establishing a frozen barrier zone to inhibit migration offluids in or out of the portion of the formation being heated, whereinat least one or more heaters is positioned greater than about 5 m from afrozen barrier zone.
 8823. The method of claim 8807, further comprisingestablishing a frozen barrier zone to inhibit migration of fluids in orout of the portion of the formation being heated, wherein at least oneor more heaters is positioned less than about 1.5 m from a frozenbarrier zone.
 8824. A method of forming a subsurface barrier in asubsurface formation, comprising: positioning a conduit in an opening ina part of the formation; positioning one or more baffles in an annulusformed between a wall of the conduit and a wall of the opening toinhibit a flow of fluids in the annulus; and using the opening to formthe subsurface barrier in the formation.
 8825. The method of claim 8824,wherein at least one baffle comprises rubberized metal.
 8826. The methodof claim 8824, wherein inhibiting the flow of fluids assists inestablishing the barrier in the formation.
 8827. The method of claim8824, wherein at least one baffle is a cement catcher.
 8828. The methodof claim 8824, further comprising flowing refrigerant through theconduit to form a low temperature barrier.
 8829. The method of claim8824, further comprising flowing refrigerant through the conduit to forma frozen barrier.
 8830. A system configured to heat at least a part of ahydrocarbon containing formation, comprising: a heater configured to beplaced in an opening in the formation; wherein the system is configuredto allow heat to transfer from the heater to a part of the formation topyrolyze at least some hydrocarbons in the formation; and wherein thesystem is configured such that the heater can be removed from theopening in the formation and redeployed in at least one alternativeopening in the formation.
 8831. The system of claim 8830, wherein theheater comprises an insulated conductor heater.
 8832. The system ofclaim 8830, wherein the heater comprises a conductor-in-conduit heater.8833. The system of claim 8830, wherein the heater comprises a naturaldistributed combustor heater.
 8834. The system of claim 8830, whereinthe heater comprises a flameless distributed combustor heater.
 8835. Thesystem of claim 8830, wherein the opening in the formation comprises anopen wellbore.
 8836. The system of claim 8830, wherein the opening inthe formation comprises an uncased wellbore.
 8837. The system of claim8830, wherein the heater is configured to be removed using a spool.8838. The system of claim 8830, wherein the heater is configured to beremoved using coiled tubing removal.
 8839. The system of claim 8830,wherein the heater is configured to be installed using a spool. 8840.The system of claim 8830, wherein the heater is configured to beinstalled using a coiled tubing installation.
 8841. The system of claim8830, wherein the opening comprises a diameter of at least approximately5 cm, and wherein the system is configured to fit in the opening. 8842.The system of claim 8830, wherein the opening comprises a diameter of atleast approximately 7 cm, and wherein the system is configured to fit inthe opening.
 8843. The system of claim 8830, wherein the openingcomprises a diameter of at least approximately 10 cm, and wherein thesystem is configured to fit in the opening.
 8844. The system of claim8830, wherein the heater is configured to be removed from the opening torepair the heater.
 8845. The system of claim 8830, wherein the heater isconfigured to be removed from the opening to replace the heater withanother heater.
 8846. A method for installing a heater of a desiredlength in a hydrocarbon containing formation, comprising: placing atleast a portion of a heater of a desired length in an opening in ahydrocarbon containing formation, wherein placing the heater in theopening comprises uncoiling at least a portion of the heater whileplacing the heater in the opening; and wherein the heater is configuredsuch that the heater can be removed from the opening in the formationand redeployed in at least one alternative opening in the formation.8847. The method of claim 8846, further comprising assembling the heaterof the desired length, wherein the assembling of the heater of thedesired length is performed at a location proximate the hydrocarboncontaining formation.
 8848. The method of claim 8847, further comprisingcoiling the heater of the desired length after forming the heater. 8849.The method of claim 8846, wherein the heater is configurable to allowheat to transfer from the heater to a part of the formation.
 8850. Themethod of claim 8846, wherein the heater comprises an insulatedconductor heater.
 8851. The method of claim 8846, wherein the heatercomprises a conductor-in-conduit heater.
 8852. The method of claim 8846,wherein the heater comprises a natural distributed combustor heater.8853. The method of claim 8846, wherein the heater comprises a flamelessdistributed combustor heater.
 8854. The method of claim 8846, whereinthe opening in the formation comprises an open wellbore.
 8855. Themethod of claim 8846, wherein the opening in the formation comprises anuncased wellbore.
 8856. The method of claim 8846, wherein the heater isconfigurable to be removed using a spool.
 8857. The method of claim8846, wherein the heater is configurable to be removed using coiledtubing removal.
 8858. The method of claim 8846, wherein the heater isconfigurable to be installed using a spool.
 8859. The method of claim8846, wherein the heater is configurable to be installed using a coiledtubing installation.
 8860. The method of claim 8846, wherein the openingcomprises a diameter of at least approximately 5 cm, and wherein theheater is configurable to fit in the opening.
 8861. The method of claim8846, wherein the opening comprises a diameter of at least approximately7 cm, and wherein the heater is configurable to fit in the opening.8862. The method of claim 8846, wherein the opening comprises a diameterof at least approximately 10 cm, and wherein the heater is configurableto fit in the opening.
 8863. The method of claim 8846, wherein theheater is configurable to be removed from the opening to repair theheater.
 8864. The method of claim 8846, wherein the heater isconfigurable to be removed from the opening to replace the heater withanother heater.
 8865. The method of claim 8846, further comprisingcoupling at least one low resistance conductor to the heater, wherein atleast one low resistance conductor is configured to be placed in anoverburden of the formation.
 8866. The method of claim 8846, furthercomprising removing at least a portion of the heater from the opening byrecoiling at least a portion of the heater.
 8867. The method of claim8846, further comprising coiling the heater on a spool.
 8868. The methodof claim 8846, further comprising uncoiling the heater on a spool. 8869.The method of claim 8846, further comprising transporting the heater ona cart from an assembly location to the opening in the hydrocarboncontaining formation.
 8870. The method of claim 8846, further comprisingtransporting the heater on a train from an assembly location to theopening in the hydrocarbon containing formation.
 8871. The method ofclaim 8846, further comprising transporting the heater on a cart from anassembly location to the opening in the hydrocarbon containingformation, wherein the cart can be further used to transport more thanone heater to more than one opening in the hydrocarbon containingformation.
 8872. The method of claim 8846, further comprisingtransporting the heater on a train from an assembly location to theopening in the hydrocarbon containing formation, wherein the train canbe further used to transport more than one heater to more than oneopening in the hydrocarbon containing formation.
 8873. The method ofclaim 8846, further comprising removing the heater from the opening inthe formation to inspect the heater and reinstall the heater in theopening.
 8874. The method of claim 8846, further comprising removing theheater from the opening in the formation to repair the heater andreinstall the heater in the opening.
 8875. The method of claim 8846,further comprising removing the heater from the opening in the formationto redeploy the heater in at least one alternative opening in theformation.
 8876. The method of claim 8846, further comprising removingthe heater from the opening in the formation to replace at least aportion of the heater.
 8877. A method of treating at least a part of ahydrocarbon containing formation in situ, comprising: placing one ormore heaters in one or more openings; providing heat from one or more ofthe heaters to at least one part of the formation; allowing the heat totransfer from one or more of the heaters to a part of the formation;removing one or more of the heaters from one or more of the openings;and redeploying one or more of the heaters removed from the one or moreopenings in one or more alternate openings.
 8878. The method of claim8877, further comprising pyrolyzing at least some hydrocarbons in theformation.
 8879. The method of claim 8877, further comprising producinga mixture from the formation.
 8880. The method of claim 8877, whereinone or more of the heaters comprises an insulated conductor heater.8881. The method of claim 8877, wherein one or more of the heaterscomprises a conductor-in-conduit heater.
 8882. The method of claim 8877,wherein one or more of the heaters comprises a natural distributedcombustor heater.
 8883. The method of claim 8877, wherein one or more ofthe heaters comprises a flameless distributed combustor heater. 8884.The method of claim 8877, wherein one or more of the openings in theformation comprises an uncased wellbore.
 8885. The method of claim 8877,wherein one or more of the openings in the formation comprises an openwellbore.
 8886. The method of claim 8877, wherein one or more of theheaters is configured to be removed using a spool.
 8887. The method ofclaim 8877, wherein one or more of the heaters is configured to beremoved using coiled tubing removal.
 8888. The method of claim 8877,wherein one or more of the heaters is configured to be installed using aspool.
 8889. The method of claim 8877, wherein one or more of theheaters is configured to be installed using a coiled tubinginstallation.
 8890. The method of claim 8877, wherein one or more of theopenings comprise a diameter of at least approximately 5 cm, and whereinthe system is configured to fit in the one or more openings.
 8891. Themethod of claim 8877, wherein one or more of the openings comprise adiameter of at least approximately 7 cm, and wherein the system isconfigured to fit in the one or more openings.
 8892. The method of claim8877, wherein one or more of the openings comprise a diameter of atleast approximately 10 cm, and wherein the system is configured to fitin the one or more openings.
 8893. The method of claim 8877, wherein oneor more of the heaters is configured to be removed from one or more ofthe openings to repair the one or more heaters.
 8894. The method ofclaim 8877, wherein one or more of the heaters is configured to beremoved from one or more of the openings to replace the one or moreheaters with another heater.
 8895. The method of claim 8877, furthercomprising maintaining a temperature within at least a portion of theformation within a pyrolysis temperature range with a lower pyrolysistemperature of about 250° C. and an upper pyrolysis temperature of about400° C.
 8896. The method of claim 8877, further comprising heating atleast a part of the formation to substantially pyrolyze at least some ofthe hydrocarbons within the formation.
 8897. The method of claim 8877,further comprising controlling a pressure and a temperature within atleast a majority of the part of the formation, wherein the pressure iscontrolled as a function of temperature.
 8898. The method of claim 8877,further comprising controlling a pressure and a temperature within atleast a majority of the part of the formation, wherein the temperatureis controlled as a function of pressure.
 8899. The method of claim 8877,wherein allowing the heat to transfer from the one or more heaters tothe part of the formation comprises transferring heat substantially byconduction.
 8900. The method of claim 8877, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 8901. The method of claim 8877, further comprisingcontrolling a pressure within at least a majority of a part of theformation, wherein the controlled pressure is at least about 2.0 barsabsolute.
 8902. The method of claim 8877, further comprising controllingformation conditions such that the produced mixture comprises a partialpressure of H₂ within the mixture greater than about 0.5 bars.
 8903. Anin situ method for heating a hydrocarbon containing formation,comprising: providing heat from one or more heaters to an opening in theformation, wherein a first end of the opening contacts the earth'ssurface at a first location, and wherein a second end of the openingcontacts the earth's surface at a second location; and allowing the heatto transfer from the opening to at least a part of the formation topyrolyze at least some hydrocarbons in the formation.
 8904. The methodof claim 8903, wherein providing heat to the opening comprises providingheat from at least one heater to the opening.
 8905. The method of claim8903, wherein providing heat to the opening comprises providing heatedmaterials from at least one heater to the opening.
 8906. The method ofclaim 8903, wherein providing heat to the opening comprises providingoxidation products from at least one heater to the opening.
 8907. Themethod of claim 8903, further comprising allowing the heat to transferfrom a conduit positioned in at least a portion of the opening. 8908.The method of claim 8907, further comprising allowing the heat totransfer from the conduit and through an annulus formed between a wallof the opening and a wall of the conduit.
 8909. The method of claim8903, wherein at least one heater comprises an oxidizer, the methodfurther comprising: providing fuel to the oxidizer; and oxidizing atleast some of the fuel.
 8910. The method of claim 8909, furthercomprising allowing heat to migrate through the opening, and therebytransfer heat to at least a part of the formation.
 8911. The method ofclaim 8909, further comprising allowing heat to migrate through theconduit, and thereby transfer heat to at least a part of the formation.8912. The method of claim 8909, further comprising allowing heat tomigrate through the annulus, and thereby transfer heat to at least apart of the formation.
 8913. The method of claim 8909, furthercomprising recycling at least some fuel to at least one additionaloxidizer.
 8914. The method of claim 8903, wherein at least one heatercomprises a surface unit, the method further comprising heating a fluidor other material using the surface unit.
 8915. The method of claim8914, allowing the heated fluid or other material to migrate through theopening, and thereby transfer heat to at least a part of the formation.8916. The method of claim 8914, allowing the heated fluid or othermaterial to migrate through the conduit, and thereby transfer heat to atleast a part of the formation.
 8917. The method of claim 8914, allowingthe heated fluid or other material to migrate through the annulus, andthereby transfer heat to at least a part of the formation.
 8918. Themethod of claim 8903, further comprising: providing fuel to a conduitpositioned in the opening; providing an oxidizing fluid to the opening;oxidizing fuel in at least one oxidizer positioned in, or coupled to,the conduit; and allowing the heat to transfer to at least a part of theformation.
 8919. The method of claim 8903, further comprising providingoxidation products to the opening proximate the first location, and thenallowing the oxidation products to exit the opening proximate the secondlocation.
 8920. The method of claim 8903, further comprising providing afluid such as steam to the opening in order to inhibit coking in orproximate the opening.
 8921. The method of claim 8903, furthercomprising controlling a pressure and a temperature within at least amajority of the part of the formation, wherein the pressure iscontrolled as a function of temperature.
 8922. The method of claim 8903,further comprising controlling a pressure and a temperature within atleast a majority of the part of the formation, wherein the temperatureis controlled as a function of pressure.
 8923. The method of claim 8903,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 8924. The method of claim 8903, furthercomprising controlling a pressure within at least a majority of the partof the formation, wherein the controlled pressure is at least about 2.0bars absolute.
 8925. The method of claim 8903, further comprisingcontrolling formation conditions such that a produced mixture comprisesa partial pressure of H₂ within the mixture greater than about 0.5 bars.8926. The method of claim 8903, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 8927. The methodof claim 8903, wherein at least a portion of the part of the formationis heated to a minimum pyrolysis temperature of about 270° C.
 8928. Asystem for in situ heating of a hydrocarbon containing formation,comprising: one or more heaters configurable to provide heat to at leasta part of the formation by transferring heat to an opening in theformation, wherein a first end of the opening contacts the earth'ssurface at a first location, and wherein a second end of the openingcontacts the earth's surface at a second location; and wherein heattransferred from the opening is configured to pyrolyze at least somehydrocarbons in the formation.
 8929. The system of claim 8928, whereintransferring heat to the opening in the formation comprises providingheat to the opening.
 8930. The system of claim 8928, whereintransferring heat to the opening in the formation comprises providingheated materials to the opening.
 8931. The system of claim 8928, whereintransferring heat to the opening in the formation comprises providingoxidation products to the opening.
 8932. The system of claim 8928,further comprising a casing positioned in at least a portion of theopening.
 8933. The system of claim 8928, wherein at least one heater isan oxidizer located in the opening, or coupled to the opening.
 8934. Thesystem of claim 8928, wherein the heaters comprise at least a firstoxidizer and a second oxidizer.
 8935. The system of claim 8928, whereinheat from the first oxidizer flow through the opening from the first endtowards the second end and heat from the second oxidizer flow throughthe opening from the second end towards the first end.
 8936. The systemof claim 8928, further comprising a conduit positionable in at least aportion of the opening.
 8937. The system of claim 8936, whereintransferring heat to the opening in the formation comprises providingheat to the conduit.
 8938. The system of claim 8936, wherein the heaterscomprise at least a first oxidizer and a second oxidizer.
 8939. Thesystem of claim 8938, wherein the second oxidizer is positioned in, orcoupled to, the conduit, and wherein the second oxidizer is configuredto provide heat to at least a part of the formation.
 8940. The system ofclaim 8938, wherein heat from the first oxidizer flow through theopening from the first end towards the second end and heat from thesecond oxidizer flow through the opening from the second end towards thefirst end.
 8941. The system of claim 8928, wherein at least one heatercomprises an oxidizer configurable to oxidize fuel to generate heat, thesystem further comprising a recycle conduit configurable to recycle atleast some of the fuel flowing with oxidation products from the oxidizerto at least one additional oxidizer.
 8942. The system of claim 8936,further comprising an annulus formed between a wall of the conduit and awall of the opening.
 8943. The system of claim 8942, whereintransferring heat to the opening in the formation comprises providingheat to the annulus.
 8944. The system of claim 8942, wherein the heaterscomprise one or more oxidizers positioned in the annulus and coupled tothe conduit, wherein a fuel is provided to the conduit, and wherein thefuel flows through the conduit to the oxidizers.
 8945. The system ofclaim 8942, wherein at least one oxidizer is positioned in, or coupledto, the annulus, and wherein at least one oxidizer is configured toprovide heat to at least a part of the formation.
 8946. The system ofclaim 8945, further comprising a first oxidizer positioned in or coupledto the annulus, and a second oxidizer positioned in or coupled to theconduit.
 8947. The system of claim 8946, wherein heat from the firstoxidizer flows to the annulus and countercurrent to heat that flows tothe conduit from the second oxidizer.
 8948. The system of claim 8946,further comprising: a first recycle conduit configurable to recycle atleast some fuel in the annulus to the second oxidizer; and a secondrecycle conduit configurable to recycle at least some fuel in theconduit to the first oxidizer.
 8949. The system of claim 8928, furthercomprising a second conduit positionable in the opening, and one or moreheaters configurable to provide heat through the second conduit to atleast a part of the formation.
 8950. The system of claim 8949, whereinthe heaters comprise at least a first oxidizer configurable to provideheat to at least a part of the formation by providing heat to theconduit, and a second oxidizer configurable to provide heat to at leasta part of the formation by providing heat to the second conduit. 8951.The system of claim 8950, wherein the first oxidizer is positionable inthe conduit, or the second oxidizer is positionable in the secondconduit.
 8952. The system of claim 8950, wherein oxidation products fromthe first oxidizer flow in a direction opposite to a flow of oxidationproducts from the second oxidizer.
 8953. The system of claim 8928,wherein at least one heater comprises an oxidizer, and furthercomprising insulation positionable proximate the oxidizer.
 8954. Thesystem of claim 8928, wherein at least one heater comprises an oxidizer,and wherein at least one oxidizer comprises a ring burner or an inlineburner.
 8955. The system of claim 8928, wherein at least one of theheaters is a surface unit configurable to provide heat to the opening.8956. The system of claim 8955, further comprising a first surface unitconfigured to provide heat, heated materials, or oxidation products tothe opening or a conduit at the first location, and a second surfaceunit configured to provide heat to the opening or a conduit at thesecond location.
 8957. The system of claim 8928, wherein heat from thefirst oxidizer flows in a direction opposite of heat.
 8958. The systemof claim 8928, wherein the system is configured to provide heat to aselected section of the formation and pyrolyze at least a part of thehydrocarbons in the selected section.